Chord Energy (WLLBW) 10-K 27 Feb 15 2014 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2014	Feb. 13, 2015	Jun. 30, 2014
Document and Entity Information [Abstract]
Entity Registrant Name	WHITING PETROLEUM CORP
Entity Central Index Key	1255474
Document Type	10-K
Document Period End Date	31-Dec-14
Amendment Flag	FALSE
Current Fiscal Year End Date	-19
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		167,041,054
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
Entity Public Float			$9,569,978,297
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No

CONSOLIDATED_BALANCE_SHEETS

CONSOLIDATED BALANCE SHEETS (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Current assets:
Cash and cash equivalents	$78,100	$699,460
Accounts receivable trade, net	543,172	341,177
Derivative assets	135,577	1,274
Prepaid expenses and other	86,150	27,707
Total current assets	842,999	1,069,618
Property and equipment:
Oil and gas properties, successful efforts method	14,949,702	10,065,150
Other property and equipment	276,582	206,385
Total property and equipment	15,226,284	10,271,535
Less accumulated depreciation, depletion and amortization	-3,083,572	-2,676,490
Total property and equipment, net	12,142,712	7,595,045
Goodwill	875,676
Debt issuance costs	53,274	48,530
Other long-term assets	104,843	120,277
TOTAL ASSETS	14,019,504	8,833,470
Current liabilities:
Accounts payable trade	62,664	107,692
Accrued capital expenditures	429,970	158,739
Revenues and royalties payable	254,018	198,558
Current portion of Production Participation Plan liability	113,391	73,264
Accrued liabilities and other	169,193	144,327
Taxes payable	63,822	50,052
Accrued interest	67,913	44,405
Deferred income taxes	47,545	648
Total current liabilities	1,208,516	777,685
Long-term debt	5,628,782	2,653,834
Deferred income taxes	1,230,630	1,278,030
Production Participation Plan liability		87,503
Asset retirement obligations	167,741	116,442
Deferred gain on sale	60,305	79,065
Other long-term liabilities	20,486	4,212
Total liabilities	8,316,460	4,996,771
Commitments and contingencies
Equity:
Common stock, $0.001 par value, 300,000,000 shares authorized; 168,346,020 issued and 166,889,152 outstanding as of December 31, 2014 and 120,101,555 issued and 118,657,245 outstanding as of December 31, 2013	168	120
Additional paid-in capital	3,385,094	1,583,542
Retained earnings	2,309,712	2,244,905
Total Whiting shareholders' equity	5,694,974	3,828,567
Noncontrolling interest	8,070	8,132
Total equity	5,703,044	3,836,699
TOTAL LIABILITIES AND EQUITY	$14,019,504	$8,833,470

CONSOLIDATED_BALANCE_SHEETS_Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)	Dec. 31, 2014	Dec. 31, 2013
CONSOLIDATED BALANCE SHEETS [Abstract]
Common stock, par value (in dollars per share)	$0.00	$0.00
Common stock, shares authorized	300,000,000	300,000,000
Common stock, shares issued	168,346,020	120,101,555
Common stock, shares outstanding	166,889,152	118,657,245

CONSOLIDATED_STATEMENTS_OF_INC

CONSOLIDATED STATEMENTS OF INCOME (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
REVENUES AND OTHER INCOME:
Oil, NGL and natural gas sales	$3,024,617	$2,666,549	$2,137,714
Gain (loss) on hedging activities		-1,958	2,338
Amortization of deferred gain on sale	30,494	31,737	29,458
Gain on sale of properties	27,657	128,648	3,423
Interest income and other	2,329	3,409	519
Total revenues and other income	3,085,097	2,828,385	2,173,452
COSTS AND EXPENSES:
Lease operating	496,925	430,221	376,424
Production taxes	253,008	225,403	171,625
Depreciation, depletion and amortization	1,089,545	891,516	684,724
Exploration and impairment	854,430	453,210	166,972
General and administrative	177,211	137,994	108,573
Interest expense	170,642	112,936	75,210
Loss on early extinguishment of debt		4,412
Change in Production Participation Plan liability		-6,980	13,824
Commodity derivative (gain) loss, net	-100,579	7,802	-85,911
Total costs and expenses	2,941,182	2,256,514	1,511,441
INCOME BEFORE INCOME TAXES	143,915	571,871	662,011
INCOME TAX EXPENSE (BENEFIT):
Current	2,625	986	-669
Deferred	76,545	204,882	248,581
Total income tax expense	79,170	205,868	247,912
NET INCOME	64,745	366,003	414,099
Net loss attributable to noncontrolling interests	62	52	90
NET INCOME AVAILABLE TO SHAREHOLDERS	64,807	366,055	414,189
Preferred stock dividends		-538	-1,077
NET INCOME AVAILABLE TO COMMON SHAREHOLDERS	$64,807	$365,517	$413,112
EARNINGS PER COMMON SHARE:
Basic (in dollars per share)	$0.53	$3.09	$3.51
Diluted (in dollars per share)	$0.53	$3.06	$3.48
WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic (in shares)	122,138	118,260	117,601
Diluted (in shares)	122,519	119,588	119,028

CONSOLIDATED_STATEMENTS_OF_COM

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013		Dec. 31, 2012
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME [Abstract]
NET INCOME	$64,745	$366,003		$414,099
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:
OCI amortization on de-designated hedges		1,236	[1],[2]	-1,476	[1],[2]
Total other comprehensive income (loss), net of tax		1,236		-1,476
COMPREHENSIVE INCOME	64,745	367,239		412,623
Comprehensive loss attributable to noncontrolling interest	62	52		90
COMPREHENSIVE INCOME ATTRIBUTABLE TO WHITING	$64,807	$367,291		$412,713
[1]	Presented net of income tax expense of $722 for the year ended December 31, 2013 and an income tax benefit of $862 for the year ended December 31, 2012.
[2]	These OCI amortization amounts on de-designated hedges are reclassified from accumulated other comprehensive income (bAOCIb) to gain (loss) on hedging activities in the consolidated statements of income.

CONSOLIDATED_STATEMENTS_OF_COM1

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME [Abstract]
OCI amortization on de-designated hedges, income tax expense	$722	($862)

CONSOLIDATED_STATEMENTS_OF_CAS

CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$64,745	$366,003	$414,099
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	1,089,545	891,516	684,724
Deferred income tax expense	76,545	204,882	248,581
Amortization of debt issuance costs and debt premium	11,984	12,405	9,518
Stock-based compensation	23,258	22,436	18,190
Amortization of deferred gain on sale	-30,494	-31,737	-29,458
Gain on sale of properties	-27,657	-128,648	-3,423
Undeveloped leasehold and oil and gas property impairments	767,627	358,455	107,855
Exploratory dry hole costs	26,327	28,725	18,428
Loss on early extinguishment of debt		4,412
Change in Production Participation Plan liability		-6,980	13,824
Non-cash portion of derivative gains	-57,465	-20,830	-115,733
Other, net	-9,030	-16,118	-18,708
Changes in current assets and liabilities:
Accounts receivable trade, net	17,618	-22,912	-55,750
Prepaid expense and other	-50,352	-15,981	2,535
Accounts payable trade and accrued liabilities	-86,480	33,360	58,647
Revenues and royalties payable	-1,963	48,988	45,798
Taxes payable	1,094	16,769	2,088
Net cash provided by operating activities	1,815,302	1,744,745	1,401,215
CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and development capital expenditures	-2,842,837	-2,349,819	-2,050,029
Acquisition of oil and gas properties, net of cash acquired	-45,573	-422,923	-125,282
Other property and equipment	-79,955	-45,304	3,852
Proceeds from sale of oil and gas properties	107,848	968,606	69,190
Issuance of note receivable		-10,530	-306
Cash paid for investing derivatives		-44,900
Cash settlements received on investing derivatives		2,371
Net cash used in investing activities	-2,860,517	-1,902,499	-1,780,318
CASH FLOWS FROM FINANCING ACTIVITIES:
Redemption of 7% Senior Subordinated Notes due 2014		-253,988
Borrowings under credit agreement	2,150,000	1,860,000	2,340,000
Repayments of borrowings under credit agreement	-1,675,000	-3,060,000	-1,920,000
Repayment of tax sharing liability	-26,373	-1,759	-2,329
Debt issuance costs	-14,901	-29,690	-2,807
Restricted stock used for tax withholdings	-11,652	-5,611	-5,695
Proceeds from stock options exercised	1,781
Preferred stock dividends paid		-538	-1,077
Net cash provided by financing activities	423,855	812,414	408,092
NET CHANGE IN CASH AND CASH EQUIVALENTS	-621,360	654,660	28,989
CASH AND CASH EQUIVALENTS:
Beginning of period	699,460	44,800	15,811
End of period	78,100	699,460	44,800
SUPPLEMENTAL CASH FLOW DISCLOSURES:
Income taxes paid (refunded), net	1,380	3,681	-268
Interest paid, net of amounts capitalized	135,150	66,541	68,005
NONCASH INVESTING AND FINANCING ACTIVITIES:
Accrued capital expenditures related to property additions	429,970	158,739	110,663
Fair value of equity issued and debt assumed in the Kodiak Acquisition	4,289,088
Whiting USA Trust II Units [Member]
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from sale of oil and gas properties			322,257
Senior Notes [Member] | 5% Senior Notes due 2019 [Member]
CASH FLOWS FROM FINANCING ACTIVITIES:
Issuance of Senior Notes		1,100,000
Senior Notes [Member] | 5.75% Senior Notes due 2021 [Member]
CASH FLOWS FROM FINANCING ACTIVITIES:
Issuance of Senior Notes		$1,204,000

CONSOLIDATED_STATEMENTS_OF_CAS1

CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2012	Dec. 31, 2013	Sep. 30, 2013
Senior Notes [Member] | 5% Senior Notes due 2019 [Member]
Interest Rate (as a percent)	5.00%		5.00%	5.00%
Senior Notes [Member] | 5.75% Senior Notes due 2021 [Member]
Interest Rate (as a percent)	5.75%		5.75%	5.75%
Senior Subordinated Notes [Member] | 7% Senior Subordinated Notes due 2014 [Member]
Interest Rate (as a percent)			7.00%
Whiting USA Trust II Units [Member]
Trust units sold to the public (in shares)	18,400,000	18,400,000

CONSOLIDATED_STATEMENTS_OF_EQU

CONSOLIDATED STATEMENTS OF EQUITY (USD $)	Total Whiting Shareholders' Equity [Member]	Total Whiting Shareholders' Equity [Member]	Total Whiting Shareholders' Equity [Member]	Total Whiting Shareholders' Equity [Member]	Preferred Stock [Member]	Common Stock [Member]	Common Stock [Member]	Common Stock [Member]	Additional Paid-in Capital [Member]	Additional Paid-in Capital [Member]	Additional Paid-in Capital [Member]	Additional Paid-in Capital [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Retained Earnings [Member]	Noncontrolling Interest [Member]	Restricted Stock Units (RSUs) [Member]	Stock Option [Member]	Common Stock [Member]	Total
In Thousands, except Share data, unless otherwise specified	Restricted Stock Units (RSUs) [Member]	Stock Option [Member]	Common Stock [Member]	USD ($)		Restricted Stock Units (RSUs) [Member]	USD ($)	USD ($)	Restricted Stock Units (RSUs) [Member]	Stock Option [Member]	Common Stock [Member]	USD ($)	USD ($)	USD ($)	USD ($)	USD ($)	USD ($)	USD ($)	USD ($)
	USD ($)	USD ($)	USD ($)						USD ($)	USD ($)	USD ($)
BALANCES at Dec. 31, 2011				$3,020,857				$118				$1,554,223	$240	$1,466,276	$8,274				$3,029,131
BALANCES (in shares) at Dec. 31, 2011					172,000			118,105,000
Increase (Decrease) in Shareholders' Equity
Net income (loss)				414,189										414,189	-90				414,099
Other comprehensive income				-1,476									-1,476						-1,476
Restricted stock issued								1				-1
Restricted stock issued (in shares)								592,000
Restricted stock forfeited (in shares)								-9,000
Restricted stock used for tax withholdings				-5,695								-5,695							-5,695
Restricted stock used for tax withholdings (in shares)								-106,000
Stock-based compensation				18,190								18,190							18,190
Preferred dividends paid				-1,077										-1,077					-1,077
BALANCES at Dec. 31, 2012				3,444,988				119				1,566,717	-1,236	1,879,388	8,184				3,453,172
BALANCES (in shares) at Dec. 31, 2012					172,000			118,582,000
Increase (Decrease) in Shareholders' Equity
Net income (loss)				366,055										366,055	-52				366,003
Other comprehensive income				1,236									1,236						1,236
Conversion of preferred stock to common				1				1											1
Conversion of preferred stock to common (in shares)					-172,000			794,000
Restricted stock issued (in shares)								941,000
Restricted stock forfeited (in shares)								-100,000
Restricted stock used for tax withholdings				-5,611								-5,611							-5,611
Restricted stock used for tax withholdings (in shares)								-115,000
Stock-based compensation				22,436								22,436							22,436
Preferred dividends paid				-538										-538					-538
BALANCES at Dec. 31, 2013				3,828,567				120				1,583,542		2,244,905	8,132				3,836,699
BALANCES (in shares) at Dec. 31, 2013								120,102,000
Increase (Decrease) in Shareholders' Equity
Net income (loss)				64,807										64,807	-62				64,745
Equity issued for Kodiak Acquisition	9,596	7,523	1,771,094				48		9,596	7,523	1,771,046					9,596	7,523	1,771,094
Equity issued for Kodiak Acquisition (in shares)						258,000	47,546,000										673,235
Exercise of stock options				1,781								1,781							1,781
Exercise of stock options (in shares)								117,000									117,123
Restricted stock issued (in shares)								908,000
Restricted stock forfeited (in shares)								-386,000
Restricted stock used for tax withholdings				-11,652								-11,652							-11,652
Restricted stock used for tax withholdings (in shares)								-199,000
Stock-based compensation				23,258								23,258							23,258
BALANCES at Dec. 31, 2014				$5,694,974				$168				$3,385,094		$2,309,712	$8,070				$5,703,044
BALANCES (in shares) at Dec. 31, 2014								168,346,000

SUMMARY_OF_SIGNIFICANT_ACCOUNT

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2014
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES [Abstract]
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	WHITING PETROLEUM CORPORATION
	NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
	1.           SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
	Description of Operations—Whiting Petroleum Corporation, a Delaware corporation, is an independent oil and gas company that explores for, develops, acquires and produces crude oil, NGLs and natural gas primarily in the Rocky Mountains and Permian Basin regions of the United States.  Unless otherwise specified or the context otherwise requires, all references in these notes to “Whiting” or the “Company” are to Whiting Petroleum Corporation and its consolidated subsidiaries.
	Basis of Presentation of Consolidated Financial Statements—The consolidated financial statements include the accounts of Whiting Petroleum Corporation, its consolidated subsidiaries and Whiting’s pro rata share of the accounts of Whiting USA Trust I (“Trust I”) pursuant to Whiting’s 15.8% ownership interest in Trust I.  Investments in entities which give Whiting significant influence, but not control, over the investee are accounted for using the equity method.  Under the equity method, investments are stated at cost plus the Company’s equity in undistributed earnings and losses.  All intercompany balances and transactions have been eliminated upon consolidation.
	Use of Estimates—The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period.  Items subject to such estimates and assumptions include (1) oil and natural gas reserves; (2) cash flow estimates used in impairment tests of long-lived assets; (3) depreciation, depletion and amortization; (4) asset retirement obligations; (5) assigning fair value and allocating purchase price in connection with business combinations, including the determination of any resulting goodwill; (6) income taxes; (7) accrued liabilities; (8) valuation of derivative instruments; and (9) accrued revenue and related receivables.  Although management believes these estimates are reasonable, actual results could differ from these estimates.
	Cash and Cash Equivalents—Cash equivalents consist of demand deposits and highly liquid investments which have an original maturity of three months or less.
	Accounts Receivable Trade—Whiting’s accounts receivable trade consist mainly of receivables from oil and gas purchasers and joint interest owners on properties the Company operates.  For receivables from joint interest owners, Whiting typically has the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings.  Generally, the Company’s oil and gas receivables are collected within two months, and to date, the Company has had minimal bad debts.
	The Company routinely assesses the recoverability of all material trade and other receivables to determine their collectability.  At December 31, 2014 and 2013, the Company had an allowance for doubtful accounts of $9 million and $4 million, respectively.
	Inventories—Materials and supplies inventories consist primarily of tubular goods and production equipment, carried at weighted-average cost.  Materials and supplies are included in other property and equipment.  Crude oil in tanks inventory is carried at the lower of the estimated cost to produce or market value and is included in prepaid expenses and other.
	Oil and Gas Properties
	Proved.  The Company follows the successful efforts method of accounting for its oil and gas properties.  Under this method of accounting, all property acquisition costs and development costs are capitalized when incurred and depleted on a units-of-production basis over the remaining life of proved reserves and proved developed reserves, respectively.  Costs of drilling exploratory wells are initially capitalized but are charged to expense if the well is determined to be unsuccessful.
	The Company assesses its proved oil and gas properties for impairment whenever events or circumstances indicate that the carrying value of the assets may not be recoverable.  The impairment test compares undiscounted future net cash flows to the assets’ net book value.  If the net capitalized costs exceed future net cash flows, then the cost of the property is written down to fair value.  Fair value for oil and gas properties is generally determined based on discounted future net cash flows.  Impairment expense for proved properties is reported in exploration and impairment expense.
	Net carrying values of retired, sold or abandoned properties that constitute less than a complete unit of depreciable property are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized in income.  Gains or losses from the disposal of complete units of depreciable property are recognized to earnings.
	Interest cost is capitalized as a component of property cost for development projects that require greater than six months to be readied for their intended use.  During 2014, 2013 and 2012, the Company capitalized interest of $4 million, $2 million and $3 million, respectively.
	Unproved.  Unproved properties consist of costs to acquire undeveloped leases as well as purchases of unproved reserves.  Undeveloped lease costs and unproved reserve acquisitions are capitalized, and individually insignificant unproved properties are amortized on a composite basis, based on past success, past experience and average lease-term lives.  The Company evaluates significant unproved properties for impairment based on remaining lease term, drilling results, reservoir performance, seismic interpretation or future plans to develop acreage.  When successful wells are drilled on undeveloped leaseholds, unproved property costs are reclassified to proved properties and depleted on a unit-of-production basis.  Impairment expense for unproved properties is reported in exploration and impairment expense.
	Exploratory.  Geological and geophysical costs, including exploratory seismic studies, and the costs of carrying and retaining unproved acreage are expensed as incurred.  Costs of seismic studies that are utilized in development drilling within an area of proved reserves are capitalized as development costs.  Amounts of seismic costs capitalized are based on only those blocks of data used in determining development well locations.  To the extent that a seismic project covers areas of both developmental and exploratory drilling, those seismic costs are proportionately allocated between development costs and exploration expense.
	Costs of drilling exploratory wells are initially capitalized, pending determination of whether the well has found proved reserves.  If an exploratory well has not found proved reserves, the costs of drilling the well and other associated costs are charged to expense.  Cost incurred for exploratory wells that find reserves, which cannot yet be classified as proved, continue to be capitalized if (a) the well has found a sufficient quantity of reserves to justify completion as a producing well, and (b) the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project.  If either condition is not met, or if the Company obtains information that raises substantial doubt about the economic or operational viability of the project, the exploratory well costs, net of any salvage value, are expensed.
	Enhanced recovery activities.  The Company carries out tertiary recovery methods on certain of its oil and gas properties in order to recover additional hydrocarbons that are not recoverable from primary or secondary recovery methods.  Acquisition costs of tertiary injectants, such as purchased CO2, for EOR activities that are used during a project’s pilot phase, or prior to a project’s technical and economic viability (i.e. prior to the recognition of proved tertiary recovery reserves) are expensed as incurred.  After a project has been determined to be technically feasible and economically viable, all acquisition costs of tertiary injectants are capitalized as development costs and depleted, as they are incurred solely for obtaining access to reserves not otherwise recoverable and have future economic benefits over the life of the project.  As CO2 is recovered together with oil and gas production, it is extracted and re-injected, and all the associated CO2 recycling costs are expensed as incurred.  Likewise costs incurred to maintain reservoir pressure are also expensed.
	Other Property and Equipment—Other property and equipment consists of (i) materials and supplies inventories, (ii) leasehold costs and development costs of our CO2 source properties and (iii) other property and equipment including, furniture and fixtures, buildings, leasehold improvements and automobiles, which are stated at cost and depreciated using the straight-line method over their estimated useful lives ranging from 4 to 30 years.
	Goodwill—Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in a business combination.  Goodwill has an indefinite useful life and is not amortized, but rather is tested by the Company for impairment annually in the second quarter or when events or changes in circumstances indicate that the fair value of a reporting unit has been reduced below its carrying value.  If the Company’s qualitative analysis indicates that it is more likely than not that the fair value of the reporting unit is less than its carrying value, the Company then performs a quantitative impairment test.  If the carrying value of the reporting unit exceeds its fair value, goodwill is written down to its implied fair value with an offsetting charge to earnings.
	Debt Issuance Costs—Debt issuance costs related to the Company’s Senior Notes and Senior Subordinated Notes are amortized to interest expense using the effective interest method over the term of the related debt.  Debt issuance costs related to the credit facility are amortized to interest expense on a straight-line basis over the borrowing term.
	Derivative Instruments—The Company enters into derivative contracts, primarily costless collars and swap contracts, to manage its exposure to commodity price risk.    All derivative instruments, other than those that meet the “normal purchase normal sale” exclusion, are recorded on the balance sheet as either an asset or liability measured at fair value.  Gains and losses from changes in the fair value of derivative instruments are recognized immediately in earnings, unless the derivative meets specific hedge accounting criteria, and the derivative has been designated as a hedge.  Effective April 1, 2009, however, the Company elected to discontinue all hedge accounting prospectively, and as of December 31, 2013, all amounts related to de-designated cash flow hedges had been reclassified into earnings.
	Cash flows from derivatives used to manage commodity price risk are classified in operating activities along with the cash flows of the underlying hedged transactions.  The Company does not enter into derivative instruments for speculative or trading purposes.
	Asset Retirement Obligations and Environmental Costs—Asset retirement obligations relate to future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment and facilities from leased acreage and returning such land to its original condition.  The fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred (typically when a well is completed or acquired or an asset is installed at the production location), and the cost of such liability increases the carrying amount of the related long-lived asset by the same amount.  The liability is accreted each period through charges to depreciation, depletion and amortization expense, and the capitalized cost is depleted on a units-of-production basis over the proved developed reserves of the related asset.  Revisions to estimated retirement obligations result in adjustments to the related capitalized asset and corresponding liability.
	Liabilities for environmental costs are recorded on an undiscounted basis when it is probable that obligations have been incurred and the amounts can be reasonably estimated.  These liabilities are not reduced by possible recoveries from third parties.
	Deferred Gain on Sale—The deferred gain on sale relates to the sale of 11,677,500 Trust I units and 18,400,000 Whiting USA Trust II (“Trust II”) units, and is amortized to income based on the units-of-production method.
	Revenue Recognition—Oil and gas revenues are recognized when production volumes are sold to a purchaser at a fixed or determinable price, delivery has occurred and title has transferred, persuasive evidence of a sales arrangement exists and collectability of the revenue is probable.  Revenues from the production of gas properties in which the Company has an interest with other producers are recognized on the basis of the Company’s net working interest (entitlement method).  Net deliveries in excess of entitled amounts are recorded as liabilities, while net under deliveries are reflected as receivables.  The Company’s aggregate imbalance positions  as of December 31, 2014 and 2013 were not significant.
	Taxes collected and remitted to governmental agencies on behalf of customers are not included in revenues or costs and expenses.
	General and Administrative Expenses—General and administrative expenses are reported net of reimbursements of overhead costs that are allocated to working interest owners which participate in oil and gas properties operated by Whiting.
	Acquisition Costs—Acquisition related expenses, which consist of external costs directly related to the Company’s acquisitions, such as advisory, legal, accounting, valuation and other professional fees, are expensed as incurred.
	Maintenance and Repairs—Maintenance and repair costs which do not extend the useful lives of property and equipment are charged to expense as incurred.  Major replacements, renewals and betterments are capitalized.
	Income Taxes—Income taxes are recognized based on earnings reported for tax return purposes in addition to a provision for deferred income taxes.  Deferred income taxes are accounted for using the liability method.  Under this method, deferred tax assets and liabilities are determined by applying the enacted statutory tax rates in effect at the end of a reporting period to the cumulative temporary differences between the tax bases of assets and liabilities and their reported amounts in the Company’s financial statements.  The effect on deferred taxes for a change in tax rates is recognized in income in the period that includes the enactment date.  A valuation allowance for deferred tax assets is established when it is more likely than not that some portion of the benefit from deferred tax assets will not be realized.  The Company’s uncertain tax positions must meet a more-likely-than-not realization threshold to be recognized, and any potential accrued interest and penalties related to unrecognized tax benefits are recognized within income tax expense.
	Earnings Per Share—Basic earnings per common share is calculated by dividing net income available to common shareholders by the weighted average number of common shares outstanding during each period.  Diluted earnings per common share is calculated by dividing adjusted net income available to common shareholders by the weighted average number of diluted common shares outstanding, which includes the effect of potentially dilutive securities.  Potentially dilutive securities for the diluted earnings per share calculations consist of unvested restricted stock awards and outstanding stock options using the treasury method, as well as convertible perpetual preferred stock using the if-converted method.  In the computation of diluted earnings per share, excess tax benefits that would be created upon the assumed vesting of unvested restricted shares or the assumed exercise of stock options (i.e. hypothetical excess tax benefits) are included in the assumed proceeds component of the treasury share method to the extent that such excess tax benefits are more likely than not to be realized.  When a loss from continuing operations exists, all potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted earnings per share.
	Industry Segment and Geographic Information—The Company has evaluated how it is organized and managed and has identified only one operating segment, which is the exploration and production of crude oil, NGLs and natural gas.  The Company considers its gathering, processing and marketing functions as ancillary to its oil and gas producing activities.  All of the Company’s operations and assets are located in the United States, and substantially all of its revenues are attributable to United States customers.
	Concentration of Credit Risk—Whiting is exposed to credit risk in the event of nonpayment by counterparties, a significant portion of which are concentrated in energy related industries.  The creditworthiness of customers and other counterparties is subject to continuing review.  The following table presents the percentages by purchaser that accounted for 10% or more of the Company’s total oil, NGL and natural gas sales for the years ended December 31, 2014, 2013 and 2012:
		2014	2013	2012
	Plains Marketing LP	17%	21%	20%
	Shell Trading US	10%	14%	14%
	Bridger Trading LLC	10%	8%	11%
	Eighty Eight Oil Company	6%	11%	11%
	Commodity derivative contracts held by the Company are with seven counterparties, all of which are participants in Whiting’s credit facility as well, and all of which have investment-grade ratings from Moody’s and Standard & Poor.  As of December 31, 2014, outstanding derivative contracts with Wells Fargo Bank, N.A., JP Morgan Chase Bank, N.A. and Canadian Imperial Bank of Commerce represented 34%,  28% and 13%, respectively, of total crude oil volumes hedged.
	Reclassifications—Certain prior period balances in the consolidated balance sheets have been reclassified to conform to the current year presentation.  Such reclassifications had no impact on net income, cash flows or shareholders’ equity previously reported.
	Adopted and Recently Issued Accounting Pronouncements—In February 2013, the FASB issued Accounting Standards Update No. 2013-04, Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date (“ASU 2013-04”).  The objective of ASU 2013-04 is to provide guidance for the recognition, measurement and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation within the scope of this guidance is fixed at the reporting date.  ASU 2013-04 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013.  The Company adopted ASU 2013-04 effective January 1, 2014, which did not have an impact on the Company’s consolidated financial statements.
	In July 2013, the FASB issued Accounting Standards Update No. 2013-11, Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists (“ASU 2013-11”).  The objective of ASU 2013-11 is to provide guidance on financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists.  ASU 2013-11 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013.  The Company adopted ASU 2013-11 effective January 1, 2014, which did not have an impact on the Company’s consolidated financial statements, other than insignificant balance sheet reclassifications.
	In May 2014, the FASB issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (“ASU 2014‑09”).  The objective of ASU 2014-09 is to clarify the principles for recognizing revenue and to develop a common revenue standard for U.S. GAAP and International Financial Reporting Standards.  ASU 2014‑09 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016.  The Company is currently evaluating the impact of adopting ASU 2014‑09, but the standard is not expected to have a significant effect on its consolidated financial statements.
	In August 2014, the FASB issued Accounting Standards Update No. 2014-15, Presentation of Financial Statements – Going Concern (“ASU 2014-15”).  The objective of ASU 2014-15 is to provide guidance on management’s responsibility to evaluate whether there is substantial doubt about a company’s ability to continue as a going concern and to provide related footnote disclosures.  ASU 2014-15 is effective for fiscal years ending after December 15, 2016, and annual and interim periods thereafter.  This standard is not expected to have an impact on the Company’s consolidated financial statements.

OIL_AND_GAS_PROPERTIES

OIL AND GAS PROPERTIES	12 Months Ended
	Dec. 31, 2014
OIL AND GAS PROPERTIES [Abstract]
OIL AND GAS PROPERTIES	2.          OIL AND GAS PROPERTIES
	Net capitalized costs related to the Company’s oil and gas producing activities at December 31, 2014 and 2013 are as follows (in thousands):
		December 31,
		2014		2013
	Proved leasehold costs	$	3,637,026	$	1,633,495
	Unproved leasehold costs		1,232,040		372,298
	Costs of completed wells and facilities		9,319,808		7,563,350
	Wells and facilities in progress		760,828		496,007
	Total oil and gas properties, successful efforts method		14,949,702		10,065,150
	Accumulated depletion		-3,003,270		-2,645,841
	Oil and gas properties, net	$	11,946,432	$	7,419,309

ACQUISITIONS_AND_DIVESTITURES

ACQUISITIONS AND DIVESTITURES	12 Months Ended
	Dec. 31, 2014
ACQUISITIONS AND DIVESTITURES [Abstract]
ACQUISITIONS AND DIVESTITURES	3.          ACQUISITIONS AND DIVESTITURES
	2014 Acquisitions
	On December 8, 2014, the Company completed the acquisition of Kodiak Oil & Gas Corp. (now known as Whiting Canadian Holding Company ULC, “Kodiak”), whereby Whiting acquired all of the outstanding common stock of Kodiak (the “Kodiak Acquisition”).  Pursuant to the terms of the Kodiak Acquisition agreement, Kodiak shareholders received 0.177 of a share of Whiting common stock in exchange for each share of Kodiak common stock they owned.  Total consideration for the Kodiak Acquisition was $1.8 billion, consisting of 47,546,139 Whiting common shares issued at the market price of $37.25 per share on the date of issuance plus the fair value of Kodiak’s outstanding equity awards assumed by Whiting.  The aggregate purchase price of the transaction was $4.3 billion, which includes the assumption of Kodiak’s outstanding debt of $2.5 billion as of December 8, 2014 and the net cash acquired of $19 million.
	Kodiak was an independent energy company focused on exploration and production of crude oil and natural gas reserves, primarily in the Williston Basin region of the United States.  As a result of the Kodiak Acquisition, Whiting acquired approximately 327,000 gross (178,000 net) acres located primarily in North Dakota, including interests in 778 producing oil and gas wells and undeveloped acreage.  Approximately 10,000 of the net acres acquired were located in Wyoming and Colorado.
	The acquisition significantly expanded the Company’s presence in the Williston Basin, adding undeveloped acreage, oil and natural gas reserves and production that were complementary to its existing asset base and operations in this area.  As a result of this acquisition, Whiting became the largest Bakken/Three Forks producer in the Williston Basin as of the acquisition date.
	The Kodiak Acquisition was accounted for using the acquisition method of accounting for business combinations.  The allocation of the preliminary estimated purchase price is based upon management’s estimates and assumptions related to the fair value of assets acquired and liabilities assumed on the acquisition date using currently available information.  Transaction costs relating to the Kodiak Acquisition were expensed as incurred.  The initial accounting for the Kodiak Acquisition is preliminary, and adjustments to provisional amounts (such as goodwill, certain accrued liabilities and their related deferred taxes), or recognition of additional assets acquired or liabilities assumed, may occur as additional information is obtained about facts and circumstances that existed as of the acquisition date.
	The preliminary consideration transferred, fair value of assets acquired and liabilities assumed, and the resulting goodwill as of the acquisition date are as follows (in thousands):
	Consideration:
	Fair value of Whiting’s common stock issued (1)		$	1,771,094
	Fair value of Kodiak restricted stock units assumed by Whiting (2)			9,596
	Fair value of Kodiak options assumed by Whiting			7,523
	Total consideration		$	1,788,213
	Fair value of liabilities assumed:
	Accounts payable trade		$	18,390
	Accrued capital expenditures			104,509
	Revenues and royalties payable			57,423
	Accrued liabilities and other			45,695
	Taxes payable			12,676
	Accrued interest			18,070
	Current deferred tax liability			30,279
	Long-term debt			2,500,875
	Asset retirement obligations			8,646
	Other long-term liabilities			15,735
	Amount attributable to liabilities assumed		$	2,812,298
	Fair value of assets acquired:
	Cash and cash equivalents		$	18,879
	Accounts receivable trade, net			219,654
	Derivative assets			85,718
	Prepaid expenses and other			8,624
	Oil and gas properties, successful efforts method:
	Proved properties			2,266,607
	Unproved properties			1,000,396
	Other property and equipment			11,347
	Long-term deferred tax asset			107,497
	Other long-term assets			6,113
	Amount attributable to assets acquired		$	3,724,835
	Goodwill		$	875,676
	_____________________
		-1		47,546,139 shares of Whiting common stock at $37.25 per share (closing price as of December 5, 2014), based on Kodiak’s 268,622,497 common shares outstanding at closing.
		-2		257,601 shares of Whiting common stock issued at $37.25 per share (closing price as of December 5, 2014), based on Kodiak’s 1,455,409 restricted stock units held by employees as of December 8, 2014.
	Goodwill recognized as a result of the Kodiak Acquisition totaled $876 million, none of which is deductible for income tax purposes.  Goodwill is primarily attributable to the operational and financial synergies expected to be realized from the acquisition, including employing optimized completion techniques on Kodiak's undrilled acreage which will improve hydrocarbon recovery, realized savings in drilling and well completion costs, the accelerated development of Kodiak’s asset base, and the acquisition of experienced oil and gas technical personnel.
	The results of operations of Kodiak from the December 8, 2014 closing date through December 31, 2014, representing approximately $46 million of revenue and $17 million of net income,  have been included in Whiting’s consolidated statements of income for the year ended December 31, 2014.
	2014 Divestitures
	On March 27, 2014, the Company completed the sale of approximately 49,900 gross (41,000 net) acres in its Big Tex prospect, which consisted mainly of undeveloped acreage as well as its interests in certain producing oil and gas wells, located in the Delaware Basin of Texas for a cash purchase price of $76 million resulting in a pre-tax gain on sale of $12 million.
	2013 Acquisitions
	On September 20, 2013, the Company completed the acquisition of approximately 39,300 gross (17,300 net) acres in the Williston Basin, including interests in 121 producing oil and gas wells and undeveloped acreage, located in Williams and McKenzie counties of North Dakota and Roosevelt and Richland counties of Montana for an initial purchase price of $261 million.  Revenue and earnings from these properties since the September 20, 2013 acquisition date are not material, and disclosures of pro forma revenues and net income for this acquisition of these wells are also not material and have not been presented accordingly.
	The acquisition was recorded using the purchase method of accounting.  The initial purchase price has been adjusted for post-closing settlements that have occurred since the acquisition date totaling $6 million.  The following table summarizes the allocation of the $256 million adjusted purchase price to the tangible assets acquired and liabilities assumed in this acquisition of oil and gas properties (in thousands):
	Purchase price		$	255,537
	Allocation of purchase price:
	Oil and gas properties, successful efforts method:
	Proved properties		$	229,002
	Unproved properties			27,335
	Oil in tank inventory			522
	Accounts receivable			578
	Asset retirement obligations			-1,900
	Total		$	255,537
	2013 Divestitures
	On October 31, 2013, the Company completed the sale of approximately 45,000 gross (32,200 net) acres in its Big Tex prospect, which consisted mainly of undeveloped acreage as well as its interests in certain producing oil and gas wells, located in the Delaware Basin of Texas for a cash purchase price of $151 million, resulting in a pre-tax gain on sale of $11 million.  Of the total net acres sold, approximately 30,800 net acres are located in Pecos County, Texas, and approximately 1,400 net acres are located in Reeves County, Texas.
	On July 15, 2013, the Company completed the sale of its interests in certain oil and gas producing properties located in its EOR projects in the Postle and Northeast Hardesty fields in Texas County, Oklahoma, including the related Dry Trail plant gathering and processing facility, oil delivery pipeline, its entire 60% interest in the Transpetco CO2 pipeline, crude oil swap contracts and certain other related assets and liabilities (collectively the “Postle Properties”) for a cash purchase price of $809 million after selling costs and post-closing adjustments.  This divestiture resulted in a pre-tax gain on sale of $109 million.  The Company used the net proceeds from this sale to repay a portion of the debt outstanding under its credit agreement.
	2012 Acquisitions
	There were no significant acquisitions during the year ended December 31, 2012.
	2012 Divestitures
	On May 18, 2012, the Company sold a 50% ownership interest in its Belfield gas processing plant, natural gas gathering system, oil gathering system and related facilities located in Stark County, North Dakota for total cash proceeds of $66 million.  Whiting used the net proceeds from the sale to repay a portion of the debt outstanding under its credit agreement.
	On March 28, 2012, the Company completed an initial public offering of units of beneficial interest in Trust II, selling 18,400,000 Trust II units at $20.00 per unit, which generated net proceeds of $322 million after underwriters’ fees, offering expenses and post-close adjustments.  The Company used the net offering proceeds to repay a portion of the debt outstanding under its credit agreement.  The net proceeds from the sale of Trust II units to the public resulted in a deferred gain on sale of $128 million.  Immediately prior to the closing of the offering, Whiting conveyed a term net profits interest in certain of its oil and gas properties to Trust II in exchange for 100% of the trust’s units issued, or 18,400,000 units.
The net profits interest entitles Trust II to receive 90% of the net proceeds from the sale of oil and natural gas production from the underlying properties.  The net profits interest will terminate on the later to occur of (1) December 31, 2021, or (2) the time when 11.79 MMBOE have been produced from the underlying properties and sold.  This is the equivalent of 10.61 MMBOE in respect of Trust II’s right to receive 90% of the net proceeds from such reserves pursuant to the net profits interest.
Unaudited Pro Forma Operating Results
The following unaudited pro forma combined results of operations for the years ended December 31, 2014 and 2013 are derived from the historical consolidated financial statements of Whiting and Kodiak and give effect to the Kodiak Acquisition as if it had occurred on January 1, 2013.
		December 31,
		2014		2013
		(in thousands, except per share data)
Total revenues		$	4,141,046	$	3,774,137
Net income available to common shareholders		$	362,376	$	576,450
Earnings per common share:
Basic		$	2.18	$	3.48
Diluted		$	2.17	$	3.46
The unaudited pro forma combined results of operations reflect pro forma adjustments based on available information and certain assumptions that the Company believes are reasonable, including (i) Whiting common stock and equity awards issued to convert Kodiak’s outstanding shares of common stock and equity awards as of the closing date of the transaction, (ii) adjustments to conform Kodiak’s historical policy of accounting for its oil and natural gas properties from the full cost method to the successful efforts method of accounting, (iii) depletion of Kodiak’s fair-valued proved oil and gas properties, (iv) adjustments to interest expense to reflect the assumption of Kodiak’s debt by Whiting, and (v) the estimated tax impacts of the pro forma adjustments.  Additionally, pro forma earnings for the year ended December 31, 2014 were adjusted to exclude $86 million of acquisition-related costs incurred by Whiting and Kodiak, and the pro forma earnings for the year ended December 31, 2013 were adjusted to include these charges.
The unaudited pro forma financial information has been prepared for informational purposes only and does not purport to represent what Whiting’s results of operations would have been had the transactions actually been consummated on the assumed dates nor are they indicative of future results of operations.  The unaudited pro forma combined financial information does not reflect future events that may occur after the transactions including, but not limited to, the anticipated realization of ongoing savings from operating efficiencies from the Kodiak Acquisition.

LONGTERM_DEBT

LONG-TERM DEBT	12 Months Ended
	Dec. 31, 2014
LONG-TERM DEBT [Abstract]
LONG-TERM DEBT	4.          LONG-TERM DEBT
	Long-term debt consisted of the following at December 31, 2014 and 2013 (in thousands):
			December 31,
			2014			2013
	Credit agreement		$	1,400,000		$	-
	6.5% Senior Subordinated Notes due 2018			350,000			350,000
	5% Senior Notes due 2019			1,100,000			1,100,000
	8.125% Senior Notes due 2019, including unamortized debt premium of $23,742			823,742			-
	5.75% Senior Notes due 2021, including unamortized debt premium of $3,180 and $3,834, respectively			1,203,180			1,203,834
	5.5% Senior Notes due 2021, including unamortized debt premium of $867			350,867			-
	5.5% Senior Notes due 2022, including unamortized debt premium of $993			400,993			-
	Total debt		$	5,628,782		$	2,653,834
	The following table shows five succeeding fiscal years of scheduled maturities for the Company’s long-term debt as of December 31, 2014 (in thousands):
			2015			2016		2017		2018		2019
	Long-term debt (1)		$	-		$	-	$	-	$	350,000	$	3,300,000
	_____________________
		-1		Refer to “Kodiak Senior Notes Repurchase Offer” below for more information.
	Credit Agreement—In August 2014, Whiting Oil and Gas Corporation (“Whiting Oil and Gas”), the Company’s wholly-owned subsidiary, entered into a Sixth Amended and Restated Credit Agreement with a syndicate of banks, which replaced its existing credit agreement upon closing of the Kodiak Acquisition on December 8, 2014.  This amended credit agreement increased the borrowing base under Whiting Oil and Gas’ credit facility to $4.5 billion, with aggregate commitments of $3.5 billion.  Subsequently in December 2014, the lenders under the credit agreement increased their aggregate commitments under this amended agreement from $3.5 billion to $4.5 billion, of which $3.5 billion relates to commitments to extend revolving credit and $1.0 billion relates to a senior secured delayed draw term loan facility (“Delayed Draw Facility”).  The Delayed Draw Facility may be used to provide cash consideration for any repurchase or redemption of Kodiak’s outstanding senior notes in connection with the Kodiak Acquisition, to pay transaction costs and for other corporate purposes.  Under the amended credit agreement, the revolving credit facility will mature on December 8, 2019, and the Delayed Draw Facility will mature on December 31, 2015.  As of December 31, 2014, the Company had $3.1  billion of available borrowing capacity, which was net of $1.4  billion in borrowings and $3 million in letters of credit outstanding.
	The borrowing base under the credit agreement is determined at the discretion of the lenders, based on the collateral value of the Company’s proved reserves that have been mortgaged to such lenders, and is subject to regular redeterminations on May 1 and November 1 of each year, as well as special redeterminations described in the credit agreement, in each case which may reduce the amount of the borrowing base.  Upon a redetermination of our borrowing base, either on a periodic or special redetermination date, if borrowings in excess of the revised borrowing capacity were outstanding, we could be forced to immediately repay a portion of our debt outstanding under the credit agreement.  A portion of the revolving credit facility in an aggregate amount not to exceed $100 million may be used to issue letters of credit for the account of Whiting Oil and Gas or other designated subsidiaries of the Company.  As of December 31, 2014, $97 million was available for additional letters of credit under the agreement.
	The credit agreement provides for interest only payments until the expiration date of the agreement, when all outstanding borrowings are due.  Interest under the revolving credit facility accrues at the Company’s option at either (i) a base rate for a base rate loan plus the margin in the table below, where the base rate is defined as the greatest of the prime rate, the federal funds rate plus 0.5% per annum, or an adjusted LIBOR rate plus 1.0% per annum, or (ii) an adjusted LIBOR rate for a Eurodollar loan plus the margin in the table below.  Additionally, the Company also incurs commitment fees as set forth in the table below on the unused portion of the aggregate commitments of the lenders under the revolving credit facility, which are included as a component of interest expense.  At December 31, 2014, the entire $1.4 billion outstanding principal balance under the credit agreement was under the revolving credit facility with a weighted average interest rate of 1.9%.
			Applicable		Applicable
			Margin for Base		Margin for		Commitment
	Ratio of Outstanding Borrowings to Borrowing Base		Rate Loans		Eurodollar Loans		Fee
	Less than 0.25 to 1.0		0.50%		1.50%		0.38%
	Greater than or equal to 0.25 to 1.0 but less than 0.50 to 1.0		0.75%		1.75%		0.38%
	Greater than or equal to 0.50 to 1.0 but less than 0.75 to 1.0		1.00%		2.00%		0.50%
	Greater than or equal to 0.75 to 1.0 but less than 0.90 to 1.0		1.25%		2.25%		0.50%
	Greater than or equal to 0.90 to 1.0		1.50%		2.50%		0.50%
	Interest under the Delayed Draw Facility accrues at the Company’s option at either (i) a base rate for a base rate loan plus (A) 1.00% per annum through March 8, 2015 and (B) 1.50% per annum from March 9, 2015 through the December 31, 2015 maturity date, or (ii) an adjusted LIBOR rate for a Eurodollar loan plus (A) 2.00% per annum through March 8, 2015 and (B) 2.50% per annum from March 9, 2015 through the December 31, 2015 maturity date.  We also incur commitment fees of 0.25% on the unused portion of the aggregate commitments of the lenders under the Delayed Draw Facility.
	The amended credit agreement contains restrictive covenants that may limit the Company’s ability to, among other things, incur additional indebtedness, sell assets, make loans to others, make investments, enter into mergers, enter into hedging contracts, incur liens and engage in certain other transactions without the prior consent of its lenders.  Except for limited exceptions, the credit agreement also restricts the Company’s ability to make any dividend payments or distributions on its common stock.  These restrictions apply to all of the net assets of the subsidiaries.  As of December 31, 2014, total restricted net assets were $6.9 billion, and the amount of retained earnings free from restrictions was $24 million.  The credit agreement requires the Company, as of the last day of any quarter, (i) to not exceed a total debt to the last four quarters’ EBITDAX ratio (as defined in the credit agreement) of 4.0 to 1.0 and (ii) to have a consolidated current assets to consolidated current liabilities ratio (as defined in the credit agreement and which includes an add back of the available borrowing capacity under the credit agreement) of not less than 1.0 to 1.0.  The Company was in compliance with its covenants under the credit agreement as of December 31, 2014.
	Under the terms of the credit agreement, at any time during which Whiting has an investment-grade debt rating from Moody’s Investors Service, Inc. or Standard & Poor’s Ratings Group and Whiting has elected, at its discretion, to effect an investment-grade rating period, (i) certain security requirements, including the borrowing base requirement, and restrictive covenants will cease to apply, (ii) certain other restrictive covenants will become less restrictive, (iii) an additional financial covenant will be imposed, and (iv) the interest rate margin applicable to all revolving borrowings as well as the commitment fee with respect to the revolving facility will be based upon the Company’s debt rating rather than the ratio of outstanding borrowings to the borrowing base.
	The obligations of Whiting Oil and Gas under the credit agreement are secured by a first lien on substantially all of Whiting Oil and Gas’ and Whiting Resource Corporation’s properties included in the borrowing base for the credit agreement.  The Company has guaranteed the obligations of Whiting Oil and Gas under the credit agreement and has pledged the stock of its subsidiaries as security for its guarantee.
	Senior Notes and Senior Subordinated Notes—In September 2010, the Company issued at par $350 million of 6.5% Senior Subordinated Notes due October 2018 (the “2018 Senior Subordinated Notes”).  The estimated fair value of these notes was $345 million and $371 million as of December 31, 2014 and 2013, respectively, based on quoted market prices for these debt securities, and such fair value is therefore designated as Level 1 within the valuation hierarchy.
	Issuance of Senior Notes.  In September 2013, the Company issued at par $1.1 billion of 5% Senior Notes due March 2019 (the “2019 Senior Notes”) and $800 million of 5.75% Senior Notes due March 2021, and issued at 101% of par an additional $400 million of 5.75% Senior Notes due March 2021 (collectively, the “2021 Senior Notes” and together with the 2019 Senior Notes, the “Whiting Senior Notes”).  The estimated fair value of the 2019 Senior Notes was $1.0 billion and $1.1 billion as of December 31, 2014 and 2013, respectively.  The estimated fair value of the 2021 Senior Notes was $1.1 billion and $1.3 billion as of December 31, 2014 and 2013, respectively.  These fair values are based on quoted market prices for these debt securities, and such fair values are therefore designated as Level 1 within the valuation hierarchy.
	Redemption of Senior Subordinated Notes.  In October 2013, the Company paid $254 million to redeem its entire $250 million aggregate principal amount of the 7% Senior Subordinated Notes due February 2014 (the “2014 Senior Subordinated Notes”) at a redemption price of 101.595%.  Concurrent with this redemption, the Company paid all accrued and unpaid interest on the 2014 Senior Subordinated Notes up to but not including the redemption date.  The Company financed the redemption of these notes with proceeds from the issuance of the Whiting Senior Notes, as discussed above.  As a result of the redemption, Whiting recognized a $4 million loss on early extinguishment of debt, which primarily consisted of a cash charge of $4 million related to the redemption premium on the 2014 Senior Subordinated Notes.
	Kodiak Senior Notes.  In conjunction with the Kodiak Acquisition, Whiting US Holding Company, a wholly-owned subsidiary of the Company, became a co-issuer of Kodiak’s outstanding principal amount of $800 million of 8.125% Senior Notes due December 2019, $350 million of 5.5% Senior Notes due January 2021, and $400 million of 5.5% Senior Notes due February 2022 (the “Kodiak Notes”).  The Kodiak Notes were recorded at their fair values of $824 million, $351 million and $401 million, respectively, on December 8, 2014, the closing date of the acquisition.  The related premiums of $24 million, $1 million and $1 million, respectively, are being amortized to interest expense over the life of the related notes.  As of December 31, 2014, the estimated fair value of the Kodiak Notes was $812 million, $351 million and $401 million, respectively, based on quoted market prices for these debt securities, and such fair value is therefore designated as Level 1 within the valuation hierarchy.
	Upon closing of the Kodiak Acquisition, the indentures under which the Kodiak Notes were issued (the “Kodiak Indentures”) were amended to (i) modify certain covenants and restrictions, (ii) to provide for unconditional and irrevocable guarantees by Whiting Petroleum Corporation and Whiting Oil and Gas of the prompt payment, when due, of any amounts owed under the Kodiak Notes and the Kodiak Indentures, and (iii) to allow Whiting US Holding Company to become a co-issuer of the Kodiak Notes.  Also in conjunction with the Kodiak Acquisition, in December 2014, each of the indentures governing the Company’s 2019 Senior Notes, 2021 Senior Notes and 2018 Senior Subordinated Notes were amended to include Whiting US Holding Company, Kodiak and Whiting Resources Corporation (formerly Kodiak Oil & Gas (USA) Inc.) as guarantors.  Shortly after closing, the Kodiak Notes were deregistered in accordance with the Securities Exchange Act of 1934, and accordingly, the Company is exempt from the reporting requirements under Rule 3-10 of Regulation S-X of the SEC with respect to the Kodiak Notes.
	Kodiak Senior Notes Repurchase Offer.  On January 7, 2015, as required under the Kodiak Indentures upon a change in control of Kodiak, Whiting offered to repurchase at 101% of par all $1,550 million principal amount of Kodiak Notes outstanding.  The repurchase offer expires on March 3, 2015.  The Company expects to fund any payments due as a result of such repurchase offer with borrowings under its revolving credit facility.
	The Whiting Senior Notes and Kodiak Notes are unsecured obligations of Whiting Petroleum Corporation and Whiting US Holding Company, respectively, and are subordinated to all of the Company’s secured indebtedness, which consists of Whiting Oil and Gas’ credit agreement.  The 2018 Senior Subordinated Notes are also unsecured obligations of Whiting Petroleum Corporation and are subordinated to all of the Company’s senior debt, which currently consists of the Whiting Senior Notes, the Kodiak Notes and Whiting Oil and Gas’ credit agreement.
	The Company’s obligations under the 2018 Senior Subordinated Notes and the Whiting Senior Notes are fully and unconditionally guaranteed by the Company’s wholly-owned subsidiaries, Whiting Oil and Gas, Whiting US Holding Company, Whiting Canadian Holding Company ULC and Whiting Resources Corporation (the “Guarantors”). Any subsidiaries other than these Guarantors are minor subsidiaries as defined by Rule 3-10(h)(6) of Regulation S‑X of the SEC.  Whiting Petroleum Corporation has no assets or operations independent of this debt and its investments in its consolidated subsidiaries.

ASSET_RETIREMENT_OBLIGATIONS

ASSET RETIREMENT OBLIGATIONS	12 Months Ended
	Dec. 31, 2014
ASSET RETIREMENT OBLIGATIONS [Abstract]
ASSET RETIREMENT OBLIGATIONS	5.          ASSET RETIREMENT OBLIGATIONS
	The Company’s asset retirement obligations represent the present value of estimated future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment and facilities from leased acreage, and land restoration (including removal of certain onshore and offshore facilities in California) in accordance with applicable local, state and federal laws.  The Company follows FASB ASC Topic 410, Asset Retirement and Environmental Obligations, to determine its asset retirement obligation amounts by calculating the present value of the estimated future cash outflows associated with its plug and abandonment obligations.  The current portions at December 31, 2014 and 2013 were $12 million and $10 million, respectively, and have been included in accrued liabilities and other.  Revisions to the liability typically occur due to changes in estimated abandonment costs or well economic lives, or if federal or state regulators enact new requirements regarding the abandonment of wells.  The following table provides a reconciliation of the Company’s asset retirement obligations for the years ended December 31, 2014 and 2013 (in thousands):
			December 31,
			2014		2013
	Asset retirement obligation at January 1		$	126,148	$	97,818
	Additional liability incurred			29,186		17,535
	Revisions in estimated cash flows (1)			25,909		12,225
	Accretion expense			13,548		10,608
	Obligations on sold properties			-7,237		-3,630
	Liabilities settled			-7,623		-8,408
	Asset retirement obligation at December 31		$	179,931	$	126,148
	_____________________
		-1		Revisions in estimated cash flows during the year ended December 31, 2014 are primarily attributable to increased estimates of future costs for oilfield goods and services required to plug and abandon wells in certain fields in the Rocky Mountains and Permian Basin regions.  Revisions in estimated cash flows during the year ended December 31, 2013 were primarily attributable to increased estimates of futures costs for oilfield goods and services required to plug and abandon wells in certain fields in the Rocky Mountains region.

DERIVATIVE_FINANCIAL_INSTRUMEN

DERIVATIVE FINANCIAL INSTRUMENTS	12 Months Ended
	Dec. 31, 2014
DERIVATIVE FINANCIAL INSTRUMENTS [Abstract]
DERIVATIVE FINANCIAL INSTRUMENTS	6.          DERIVATIVE FINANCIAL INSTRUMENTS
	The Company is exposed to certain risks relating to its ongoing business operations, and Whiting uses derivative instruments to manage its commodity price risk.  Whiting follows FASB ASC Topic 815, Derivatives and Hedging, to account for its derivative financial instruments.
	Commodity Derivative Contracts—Historically, prices received for crude oil and natural gas production have been volatile because of seasonal weather patterns, supply and demand factors, worldwide political factors and general economic conditions.  Whiting enters into derivative contracts, such as costless collars,  swaps and fixed-differential contracts to achieve a more predictable cash flow by reducing its exposure to commodity price volatility.  Commodity derivative contracts are thereby used to ensure adequate cash flow to fund the Company’s capital programs and to manage returns on acquisitions and drilling programs.  The Company does not enter into derivative contracts for speculative or trading purposes.
	Crude Oil Costless Collars and Swaps.  Costless collars are designed to establish floor and ceiling prices on anticipated future oil or gas production, while swaps are designed to establish a fixed price for anticipated future oil or gas production.  While the use of these derivative instruments limits the downside risk of adverse price movements, they may also limit future revenues from favorable price movements.
	The table below details the Company’s costless collar and swap derivatives entered into to hedge forecasted crude oil production revenues as of February 13, 2015, including certain oil collars and swaps assumed in the Kodiak Acquisition.
					Whiting Petroleum Corporation
	Derivative				Contracted Crude		Weighted Average NYMEX Price
	Instrument		Period		Oil Volumes (Bbl)		Collar Ranges for Crude Oil (per Bbl)
	Three-way collars (1)		Jan - Dec 2015		3,600,000		$50.83 - $62.50 - $83.81
			Jan - Dec 2016		6,600,000		$43.18 - $53.18 - $76.26
	Collars		Jan - Dec 2015		1,309,500		$52.47 - $59.26
			Jan - Dec 2016		3,000,000		$51.00 - $63.48
			Jan - Dec 2017		3,000,000		$53.00 - $70.44
	Swaps		Jan - Dec 2015		3,556,560		$86.05
			Total		21,066,060
	_____________________
		-1		A three-way collar is a combination of options: a sold call, a purchased put and a sold put.  The sold call establishes a maximum price (ceiling) Whiting will receive for the volumes under contract.  The purchased put establishes a minimum price (floor), unless the market price falls below the sold put (sub-floor), at which point the minimum price would be NYMEX plus the difference between the purchased put and the sold put strike price.
	In March 2013, Whiting entered into certain crude oil swap contracts in order to achieve more predictable cash flows and manage returns on certain oil and gas properties that the Company was considering for monetization.  Accordingly, the acquisition of these swap contracts and cash receipts from settlements of these swap positions have been reflected as an investing activity in the statement of cash flows.  On July 15, 2013, upon closing of the sale of the Postle Properties discussed in the Acquisitions and Divestitures footnote, these crude oil swaps were novated to the buyer.  Cash settlements that do not relate to investing derivatives or that do not have a significant financing element are reflected as operating activities in the statement of cash flows.
	Fixed-differential Crude Oil Contracts.  The Company has entered into two long-term crude oil sales and delivery contracts for oil volumes produced from its Redtail field in Colorado.  Under the terms of these agreements, Whiting has committed to deliver certain fixed volumes of crude oil from 2015 through 2020 at a price equal to NYMEX less the fixed differentials specified in the agreements.  As of December 31, 2014, the Company determined that it is no longer probable that future oil production from its Redtail field will be sufficient to meet the minimum volume requirements specified in these contracts, and accordingly, that the Company will not settle these contracts through physical delivery of crude oil volumes.  As a result, Whiting has determined that these contracts no longer qualify for the “normal purchase normal sale” exclusion, and has therefore reflected them at fair value in the consolidated financial statements.  As of December 31, 2014, the estimated fair value of these derivative contracts was an asset of $54 million.
	Embedded Commodity Derivative Contract—In May 2011, Whiting entered into a long-term contract to purchase CO2 for use in its EOR project that is being carried out at its North Ward Estes field in Texas.  This contract contained a price adjustment clause that was linked to changes in NYMEX crude oil prices.  The Company had determined that the portion of this contract linked to NYMEX oil prices was not clearly and closely related to the host contract, and the Company therefore bifurcated this embedded pricing feature from its host contract and reflected it at fair value in the consolidated financial statements.  The Company had terminated this contract, however, prior to the issuance date of these financial statements, and the fair value of this embedded derivative was therefore zero as of December 31, 2014.
	Derivative Instrument Reporting—All derivative instruments are recorded in the consolidated financial statements at fair value, other than derivative instruments that meet the “normal purchase normal sale” exclusion.  The following tables summarize the effects of commodity derivative instruments on the consolidated statements of income for the years ended December 31, 2014 and 2013 (in thousands):
					Loss Reclassified from AOCI into
					Income (Effective Portion)
	ASC 815 Cash Flow				Year Ended December 31,
	Hedging Relationships (1)		Income Statement Classification		2014			2013
	Commodity contracts		Gain (loss) on hedging activities		$	-		$	-1,958
	_____________________
		-1		Effective April 1, 2009, the Company de-designated all of its commodity derivative contracts that had been previously designated as cash flow hedges and elected to discontinue hedge accounting prospectively.  As a result, such mark-to-market values at March 31, 2009 were frozen in AOCI as of the de-designation date and were reclassified into earnings as the original hedged transactions affected income.  As of December 31, 2013, all amounts previously in AOCI had been reclassified into earnings.
					(Gain) Loss Recognized in Income
	Not Designated as				Year Ended December 31,
	ASC 815 Hedges		Income Statement Classification		2014			2013
	Commodity contracts		Commodity derivative (gain) loss, net		$	-136,995		$	20,503
	Embedded commodity contracts		Commodity derivative (gain) loss, net			36,416			-12,701
	Total				$	-100,579		$	7,802
	Offsetting of Derivative Assets and Liabilities.  With each individual financial derivative counterparty, the Company typically has numerous hedge positions that span a several-month time period and that typically result in both fair value asset and liability positions held with that counterparty, which positions are all offset to a single fair value asset or liability amount at the end of each reporting period.  The Company nets its financial derivative instrument fair value amounts executed with the same counterparty pursuant to ISDA master agreements, which provide for net settlement over the term of the contract and in the event of default or termination of the contract.  The following tables summarize the location and fair value amounts of all derivative instruments in the consolidated balance sheets, as well as the gross recognized derivative assets, liabilities and amounts offset in the consolidated balance sheets (in thousands):
					December 31, 2014 (1)
										Net
					Gross					Recognized
					Recognized			Gross		Fair Value
	Not Designated as				Assets/			Amounts		Assets/
	ASC 815 Hedges		Balance Sheet Classification		Liabilities			Offset		Liabilities
	Derivative assets:
	Commodity contracts		Derivative assets		$	154,329		$	-18,752	$	135,577
	Commodity contracts		Other long-term assets			45,459			-		45,459
	Total derivative assets				$	199,788		$	-18,752	$	181,036
	Derivative liabilities:
	Commodity contracts				$	18,752		$	-18,752	$	-
	Total derivative liabilities				$	18,752		$	-18,752	$	-
					December 31, 2013 (1)
										Net
					Gross					Recognized
					Recognized			Gross		Fair Value
	Not Designated as				Assets/			Amounts		Assets/
	ASC 815 Hedges		Balance Sheet Classification		Liabilities			Offset		Liabilities
	Derivative assets:
	Commodity contracts		Derivative assets		$	23,752		$	-22,478	$	1,274
	Embedded commodity contracts		Other long-term assets			36,416			-		36,416
	Total derivative assets				$	60,168		$	-22,478	$	37,690
	Derivative liabilities:
	Commodity contracts		Accrued liabilities and other		$	25,960		$	-22,478	$	3,482
	Total derivative liabilities				$	25,960		$	-22,478	$	3,482
	_____________________
		-1		Because counterparties to the Company’s financial derivative contracts are lenders under Whiting Oil and Gas’ credit agreement, which eliminates its need to post or receive collateral associated with its derivative positions, columns for cash collateral pledged or received have not been presented in the tables above.
	Contingent Features in Financial Derivative Instruments.  None of the Company’s derivative instruments contain credit-risk-related contingent features.  Counterparties to the Company’s financial derivative contracts are high credit-quality financial institutions that are lenders under Whiting’s credit agreement.  The Company uses only credit agreement participants to hedge with, since these institutions are secured equally with the holders of Whiting’s bank debt, which eliminates the potential need to post collateral when Whiting is in a derivative liability position.  As a result, the Company is not required to post letters of credit or corporate guarantees for its financial derivative counterparties in order to secure contract performance obligations.

FAIR_VALUE_MEASUREMENTS

FAIR VALUE MEASUREMENTS	12 Months Ended
	Dec. 31, 2014
FAIR VALUE MEASUREMENTS [Abstract]
FAIR VALUE MEASUREMENTS	7.          FAIR VALUE MEASUREMENTS
	Cash and cash equivalents, accounts receivable and payable are carried at cost, which approximates their fair value because of the short-term maturity of these instruments.  The Company’s credit agreement has a recorded value that approximates its fair value since its variable interest rate is tied to current market rates.  The Company’s Senior Notes (including the Kodiak Notes) and Senior Subordinated Notes are recorded at cost, and the fair values of these instruments are included in the Long-Term Debt footnote.  The Company’s derivative financial instruments are recorded at fair value and include a measure of the Company’s own nonperformance risk or that of its counterparties as appropriate.
	The Company follows FASB ASC Topic 820, Fair Value Measurement and Disclosure, which establishes a three-level valuation hierarchy for disclosure of fair value measurements.  The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement.  The three levels are defined as follows:
		·		Level 1:  Quoted Prices in Active Markets for Identical Assets – inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets.
		·		Level 2:  Significant Other Observable Inputs – inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.
		·		Level 3:  Significant Unobservable Inputs – inputs to the valuation methodology are unobservable and significant to the fair value measurement.
	A financial instrument’s categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement.  The Company’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability.  The Company reflects transfers between the three levels at the beginning of the reporting period in which the availability of observable inputs no longer justifies classification in the original level.
	The following tables present information about the Company’s financial assets and liabilities measured at fair value on a recurring basis as of December 31, 2014 and 2013, and indicate the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair values (in thousands):
											Total Fair Value
			Level 1			Level 2		Level 3			31-Dec-14
	Financial Assets
	Commodity derivatives – current		$	-		$	127,506	$	8,071		$	135,577
	Commodity derivatives – non-current			-			-		45,459			45,459
	Total financial assets		$	-		$	127,506	$	53,530		$	181,036
											Total Fair Value
			Level 1			Level 2		Level 3			31-Dec-13
	Financial Assets
	Commodity derivatives – current		$	-		$	1,274	$	-		$	1,274
	Embedded commodity derivatives – non-current			-			-		36,416			36,416
	Total financial assets		$	-		$	1,274	$	36,416		$	37,690
	Financial Liabilities
	Commodity derivatives – current		$	-		$	3,482	$	-		$	3,482
	Total financial liabilities		$	-		$	3,482	$	-		$	3,482
	The following methods and assumptions were used to estimate the fair values of the assets and liabilities in the tables above:
	Commodity Derivatives.  Commodity derivative instruments consist mainly of costless collars and swap contracts for crude oil.  The Company’s costless collars and swaps are valued based on an income approach.  Both the option and swap models consider various assumptions, such as quoted forward prices for commodities, time value and volatility factors.  These assumptions are observable in the marketplace throughout the full term of the contract, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace, and are therefore designated as Level 2 within the valuation hierarchy.  The discount rates used in the fair values of these instruments include a measure of either the Company’s or the counterparty’s nonperformance risk, as appropriate.  The Company utilizes its counterparties’ valuations to assess the reasonableness of its own valuations.
	In addition, the Company has two long-term crude oil sales and delivery contracts, whereby it has committed to deliver certain fixed volumes of crude oil at a price equal to NYMEX less the fixed differentials specified in the agreement.    Whiting has determined that the contracts do not meet the “normal purchase normal sale” exclusion, and has therefore reflected these contracts at fair value in its consolidated financial statements.  These commodity derivatives are valued based on an income approach, which considers various assumptions, including quoted forward prices for commodities, market differentials for crude oil, U.S. Treasury rates and either the Company’s or the counterparty’s nonperformance risk, as appropriate.
	The assumptions used in the valuation of the fixed-differential contracts include certain market differential metrics that are unobservable during the term of the contracts.  Such unobservable inputs are significant to the contract valuation methodology, and the contracts’ fair values are therefore designated as Level 3 within the valuation hierarchy.
	Embedded Commodity Derivatives.  The embedded commodity derivative was related to a long-term CO2  purchase contract, which had a price adjustment clause linked to changes in NYMEX crude oil prices.    Whiting determined that the portion of this contract linked to NYMEX oil prices was not clearly and closely related to its corresponding host contract, and the Company therefore bifurcated this embedded pricing feature from the host contract and reflected it at fair value in its consolidated financial statements as of December 31, 2013.    The assumptions used in the CO2  contract valuation, which was based on the income approach, included certain oil price metrics that were unobservable during the term of the contract.  Such unobservable oil price inputs were significant to the CO2  contract valuation methodology, and the contract’s fair value was therefore designated as Level 3 within the valuation hierarchy.  Because the Company subsequently terminated this CO2 purchase contract, however, its embedded derivative had a fair value of zero as of December 31, 2014.
	Level 3 Fair Value Measurements.    A third-party valuation specialist is utilized to determine the fair value of the commodity derivative instruments designated as Level 3.  The Company reviews these valuations (including the related model inputs and assumptions) and analyzes changes in fair value measurements between periods.  The Company corroborates such inputs, calculations and fair value changes using various methodologies, and reviews unobservable inputs for reasonableness utilizing relevant information from other published sources.
	The following table presents a reconciliation of changes in the fair value of financial assets (liabilities) designated as Level 3 in the valuation hierarchy for the years ended December 31, 2014 and 2013 (in thousands):
			Year Ended
			December 31,
			2014			2013
	Fair value asset, beginning of period		$	36,416		$	23,715
	Unrealized gains (losses) on commodity derivative contracts included in earnings (1)			17,114			12,701
	Transfers into (out of) Level 3			-			-
	Fair value asset, end of period		$	53,530		$	36,416
	_____________________
		-1		Included in commodity derivative (gain) loss, net in the consolidated statements of income.
	Quantitative Information About Level 3 Fair Value Measurements.  The significant unobservable inputs used in the fair value measurement of the Company’s commodity derivative contracts designated as Level 3 are as follows:
			Fair Value at
			31-Dec-14		Valuation		Unobservable	Amount
			(in thousands)		Technique		Input	(per Bbl)
	Commodity derivative contracts		$53,530		Income approach		Market differential for crude oil	$5.74
	Sensitivity to Changes in Significant Unobservable Inputs.  As presented above, the significant unobservable inputs used in the fair value measurement of Whiting’s commodity derivative contracts are the market differentials for crude oil over the term of the contracts.  Significant increases (decreases) in these unobservable inputs in isolation would result in significantly lower (higher) fair value asset measurement.
	Nonrecurring Fair Value Measurements.  The Company applies the provisions of the fair value measurement standard to its nonrecurring, non-financial measurements, including proved oil and gas property impairments.  These assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value adjustments only in certain circumstances.  The following tables present information about the Company’s non-financial assets and liabilities measured at fair value on a nonrecurring basis as of December 31, 2014 and 2013, and indicates the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair values (in thousands):
																Loss (Before
			Net Carrying													Tax) Year
			Value as of													Ended
			December 31,			Fair Value Measurements Using										December 31,
			2014			Level 1			Level 2					Level 3		2014
	Proved property impairments (1)		$	179,155		$	-		$	-				$	179,155	$	629,450
	_____________________
		-1		During the year ended December 31, 2014, proved oil and gas properties with a carrying amount of $763 million were written down to their fair value of $176 million, resulting in a non-cash impairment charge of $587 million.  The impairment primarily consisted of non-core oil and gas properties, that are not currently being developed, in Colorado, Louisiana, North Dakota and Utah and related to the decrease in the forward price curve for crude oil and natural gas on December 31, 2014 and the associated decline in oil and gas reserves in those areas.  Also during the year ended December 31, 2014, proved CO2 properties at the Bravo Dome field in New Mexico with a carrying amount of $45 million were written down to their fair value of $3 million, resulting in a non-cash impairment charge of $42 million.
													Loss (Before
			Net Carrying										Tax) Year
			Value as of										Ended
			December 31,			Fair Value Measurements Using							December 31,
			2013			Level 1		Level 2			Level 3		2013
	Proved property impairments (1)		$	106,114		$	-	$	-		$	106,114	$	267,109
	_____________________
		-1		During the year ended December 31, 2013, proved oil and gas properties with a carrying amount of $373 million were written down to their fair value of $106 million, resulting in a non-cash impairment charge of $267 million.  The impairment consisted of (i) a $221 million write-down in the Rocky Mountains region and Michigan related to the decrease in the forward price curve for natural gas at December 31, 2013 and the associated decline in gas reserves in those areas and (ii) a $46 million write-down in the Rocky Mountains region related to well performance and associated changes in reserves during the fourth quarter of 2013.
	The following methods and assumptions were used to estimate the fair values of the non-financial liabilities in the tables above:
	Proved Property Impairments.  Once the Company has determined that a proved property impairment has occurred, the cost of the property is written down to its fair value, which is determined using net discounted future cash flows from the producing property, and such discounted cash flows are developed using the income approach.  The discounted cash flows are based on management’s expectations for the future.  Unobservable inputs include estimates of future oil and gas or CO2 production, as the case may be, from the Company’s reserve reports, commodity prices based on sales contract terms or NYMEX forward price curves as of the date of the estimate (adjusted for basis differentials), estimated operating and development costs, and a risk-adjusted discount rate (all of which are designated as Level 3 inputs within the fair value hierarchy).

DEFERRED_COMPENSATION

DEFERRED COMPENSATION	12 Months Ended
	Dec. 31, 2014
DEFERRED COMPENSATION [Abstract]
DEFERRED COMPENSATION	8.          DEFERRED COMPENSATION
	Production Participation Plan—The Company had a Production Participation Plan (the “Plan”) in which all employees participated.  On June 11, 2014, the Board of Directors of the Company terminated the Plan effective December 31, 2013.  Prior to Plan termination, interests in oil and gas properties acquired, developed or sold during the year were allocated to the Plan on an annual basis as determined by the Compensation Committee of the Company’s Board of Directors.  Once allocated, the interests (not legally conveyed) were fixed.  Interest allocations prior to 1995 consisted of 2%‑3% overriding royalty interests.  Interest allocations after 1995 were 1.75%‑5% of oil and gas sales less lease operating expenses and production taxes.
	Employees vested in the Plan ratably at 20% per year over a five-year period.  However, pursuant to the terms of the Plan, upon Plan termination all employees fully vested, and the Company is required to distribute to each Plan participant an amount, based upon the valuation method set forth in the Plan, in a lump sum payment twelve months after the date of termination.  This distribution includes the value of proved undeveloped oil and gas properties (“PUDs”) awarded upon Plan termination and is based on forecasted commodity prices for crude oil, NGLs and natural gas as of December 31, 2013.  The fully vested amount due to Plan participants totals $113 million and has been reflected as a current payable, as it will be distributed to Plan participants during the first half of 2015.    As of December 31, 2014, a portion of this liability representing a regular distribution under the Plan totaling $41 million had been paid to the Company’s third-party payroll administrator.  However, these funds were not distributed by the payroll administrator to Plan participants until January 2015.  The final Plan distribution payment will be made in June 2015.
	Accrued compensation expense under the Plan for the year ended December 31, 2014 primarily relates to the change in liability for employee vestings and PUDs assigned upon Plan termination and amounted to $24 million charged to general and administrative expense and $2 million charged to exploration expense.  Accrued compensation expense under the Plan for the years ended December 31, 2013 and 2012 amounted to $66 million and $45 million, respectively, charged to general and administrative expense and $7 million and $4 million, respectively, charged to exploration expense.    Of the aggregate $73 million of accrued compensation under the Plan as of December 31, 2013, $24 million relates to the sale of the Postle Properties, which is further described in the Acquisitions and Divestitures footnote.
	Prior to Plan termination, the Company recorded non-cash changes in the present value of estimated future payments under the Plan as a separate line item in the consolidated statements of income.  As a result of Plan termination, all changes in the Plan liability during 2014 related to cash termination payments to be made in 2015.    The following table presents changes in the Plan’s estimated long-term liability (in thousands):
		Year Ended December 31,
			2014		2013
	Long-term Production Participation Plan liability at January 1	$	87,503	$	94,483
	Change in liability for accretion, vesting, changes in estimates and new Plan year activity prior to Plan termination		-		66,284
	Change in liability for vesting and PUDs assigned upon Plan termination		25,888		-
	Amount reflected as a current liability		-113,391		-73,264
	Long-term Production Participation Plan liability at December 31	$	-	$	87,503
	401(k) Plan—The Company has a defined contribution retirement plan for all employees.  The plan is funded by employee contributions and discretionary Company contributions.  The Company’s contributions for 2014, 2013 and 2012 were $9 million, $8 million and $6 million, respectively.  Employees vest in employer contributions at 20% per year of completed service.

SHAREHOLDERS_EQUITY_AND_NONCON

SHAREHOLDERS' EQUITY AND NONCONTROLLING INTEREST	12 Months Ended
	Dec. 31, 2014
SHAREHOLDERS' EQUITY AND NONCONTROLLING INTEREST [Abstract]
SHAREHOLDERS' EQUITY AND NONCONTROLLING INTEREST	9.          SHAREHOLDERS’ EQUITY AND NONCONTROLLING INTEREST
	6.25% Convertible Perpetual Preferred Stock—In June 2009, the Company completed a public offering of 6.25% convertible perpetual preferred stock (“preferred stock”), selling 3,450,000 shares at a price of $100.00 per share.  As a result of voluntary conversions and the Company exercising its right to mandatorily convert shares of preferred stock effective June 27, 2013, all 172,129 remaining shares of preferred stock outstanding on March 31, 2013 were converted into 792,919 shares of common stock.  As of December 31, 2014, no shares of preferred stock remained issued or outstanding.
	Each holder of the preferred stock was entitled to an annual dividend of $6.25 per share to be paid quarterly in cash, common stock or a combination thereof on March 15, June 15, September 15 and December 15, once such dividend had been declared by Whiting’s board of directors.
	Equity Incentive Plan—At the Company’s 2013 Annual Meeting held on May 7, 2013, shareholders approved the Whiting Petroleum Corporation 2013 Equity Incentive Plan (the “2013 Equity Plan”), which replaced the Whiting Petroleum Corporation 2003 Equity Incentive Plan (the “2003 Equity Plan”) and includes the authority to issue 5,300,000 shares of the Company’s common stock.  Upon shareholder approval of the 2013 Equity Plan, the 2003 Equity Plan was terminated.  The 2003 Equity Plan continues to govern awards that were outstanding as of the date of its termination, which remain in effect pursuant to their terms. Any shares netted or forfeited after May 7, 2013 under the 2003 Equity Plan will be available for future issuance under the 2013 Equity Plan. Under the 2013 Equity Plan, no employee or officer participant may be granted options for more than 600,000 shares of common stock, stock appreciation rights relating to more than 600,000 shares of common stock, or more than 300,000 shares of restricted stock during any calendar year.  On December 8, 2014, the Company increased the number of shares issuable under the 2013 Equity Plan by 978,161 shares to accommodate for the conversion of Kodiak’s outstanding equity awards to Whiting equity awards upon closing of the Kodiak Acquisition.  Any shares netted or forfeited under this increased availability will be cancelled and will not be available for future issuance under the 2013 Equity Plan.  As of December 31, 2014, 5,048,433 shares of common stock remained available for grant under the 2013 Equity Plan.
	For the years ended December 31, 2014, 2013 and 2012, total stock compensation expense recognized for restricted share awards and stock options was $23 million, $22 million and $18 million, respectively.
	Equity Awards Assumed in Kodiak Acquisition.  Upon closing of the Kodiak Acquisition, the Company assumed all of Kodiak’s outstanding equity awards, including restricted stock awards, restricted stock units and stock options.  Kodiak’s outstanding equity awards held by employees were converted into Whiting’s equity awards using a conversion ratio of 0.177.  The outstanding restricted stock awards and restricted stock units vested upon closing of the transaction, and the $10 million estimated fair value of the 257,601 shares of Whiting common stock issued to convert these awards was recorded as part of the purchase consideration.
	The estimated fair value of the 673,235 Whiting options issued in exchange for Kodiak’s outstanding options was approximately $8 million, based on a Black-Scholes option-pricing model.  Of this value, approximately $7 million was attributable to service rendered prior to the date of acquisition and was recorded as part of the purchase consideration, and the remaining $1 million will be expensed over the remaining service term of the replacement stock option awards.  The unvested stock option awards will vest over a one to three-year service period from the grant date and are exercisable immediately upon vesting through the tenth anniversary of the grant date.  The following table summarizes the assumptions used to estimate the fair value of stock options assumed in the Kodiak Acquisition:
			2014
	Risk-free interest rate		0.08% - 1.90%
	Expected volatility		40.3% - 49.7%
	Expected term		2.0 yrs. - 6.1 yrs.
	Dividend yield		-
	The weighted average fair value of these options, as determined by the Black-Scholes valuation model, was $12.20 per share as of the December 8, 2014 closing date of the Kodiak Acquisition.
	Restricted Shares.  Restricted stock awards for executive officers and employees generally vest ratably over a three-year service period, while awards to directors generally vest ratably over a one-year service period.  The Company uses historical data and projections to estimate expected employee behaviors related to restricted stock forfeitures.  The expected forfeitures are then included as part of the grant date estimate of compensation cost.  For service-based restricted stock awards, the grant date fair value is determined based on the closing bid price of the Company’s common stock on the grant date.
	In January 2014, 2013 and 2012, 750,681 shares, 751,872 shares and 444,501 shares, respectively, of restricted stock, subject to certain market-based vesting criteria in addition to the standard three-year service condition, were granted to executive officers under the Equity Plan.  Vesting each year is subject to the condition that Whiting’s stock price increases by a greater percentage (or decreases by a lesser percentage) than the average percentage increase (or decrease, respectively) of the stock prices of a peer group of companies.  The market-based conditions must be met in order for the stock awards to vest, and it is therefore possible that no shares could vest in one or more of the three-year vesting periods.  However, the Company recognizes compensation expense for awards subject to market conditions regardless of whether it becomes probable that these conditions will be achieved or not, and compensation expense is not reversed if vesting does not actually occur.
	For these awards subject to market conditions, the grant date fair value was estimated using a Monte Carlo valuation model.  The Monte Carlo model is based on random projections of stock price paths and must be repeated numerous times to achieve a probabilistic assessment.  Expected volatility was calculated based on the historical volatility of Whiting’s common stock, and the risk-free interest rate is based on U.S. Treasury yield curve rates with maturities consistent with the three-year vesting period.  The key assumptions used in valuing the market-based restricted shares were as follows:
			2014		2013		2012
	Number of simulations		65,000		65,000		65,000
	Expected volatility		42.30%		43.10%		51.90%
	Risk-free interest rate		0.86%		0.41%		0.35%
	Dividend yield		-		-		-
	The grant date fair value of the market-based restricted stock as determined by the Monte Carlo valuation model was $26.59 per share, $23.01 per share and $29.45 per share in January 2014, 2013 and 2012, respectively.
	The following table shows a summary of the Company’s nonvested restricted stock as of December 31, 2012, 2013 and 2014 as well as activity during the years then ended:
						Weighted Average
			Number			Grant Date
			of Shares			Fair Value
	Restricted stock awards nonvested, January 1, 2012			724,395		$	29.88
	Granted			592,400			34.45
	Vested			-357,170			17.91
	Forfeited			-8,599			51.72
	Restricted stock awards nonvested, December 31, 2012			951,026			37.02
	Granted			940,792			27.59
	Vested			-347,824			35.32
	Forfeited			-99,684			30.95
	Restricted stock awards nonvested, December 31, 2013			1,444,310			31.71
	Granted			907,856			32.41
	Assumed in Kodiak Acquisition (1)			304,926			37.25
	Vested			-814,439			34.05
	Forfeited			-385,785			34.86
	Restricted stock awards nonvested, December 31, 2014			1,456,868		$	31.16
	_____________________
		-1		Kodiak’s existing restricted stock units and restricted stock awards held by employees, which automatically converted into 257,601 restricted stock units and 47,325 restricted stock awards of Whiting and vested upon closing of the Kodiak Acquisition.
	As of December 31, 2014, there was $13 million of total unrecognized compensation cost related to unvested restricted stock granted under the stock incentive plans.  That cost is expected to be recognized over a weighted average period of 1.7 years. For the years ended December 31, 2014, 2013 and 2012, the total fair value of restricted stock vested was $31 million, $17 million and $19 million, respectively.
	Stock Options.  Stock options may be granted to certain executive officers of the Company with exercise prices equal to the closing market price of the Company’s common stock on the grant date.  There were no stock options granted under either the 2003 Equity Plan or the 2013 Equity Plan during 2014 or 2013, other than the 673,235 stock options assumed in connection with the Kodiak Acquisition.  In January 2012, 45,359 stock options were granted under the 2003 Equity Plan.  The Company’s stock options vest ratably over a three-year service period from the grant date and are exercisable immediately upon vesting through the tenth anniversary of the grant date.
	The Company uses a Black-Scholes option-pricing model to estimate the fair value of stock option awards.  Because the Company first granted stock options in 2009, it does not have historical exercise data upon which to estimate the expected term of the options.  As such, the Company has elected to estimate the expected term of the stock options granted using the “simplified” method for “plain vanilla” options.  The expected volatility at the grant date is based on the historical volatility of Whiting’s common stock, and the risk-free interest rate is determined based on the yield on U.S. Treasury strips with maturities similar to those of the expected term of the stock options.  The following table summarizes the assumptions used to estimate the grant date fair value of stock options awarded in 2012:
			2012
	Risk-free interest rate		1.19%
	Expected volatility		61.40%
	Expected term		6.0 yrs.
	Dividend yield		-
	The grant date fair value of the stock options awarded, as determined by the Black-Scholes valuation model, was $28.88 per share in January 2012.
	The following table shows a summary of the Company’s stock options outstanding as of December 31, 2012, 2013 and 2014 as well as activity during the years then ended:
										Weighted
										Average
					Weighted			Aggregate		Remaining
					Average			Intrinsic		Contractual
			Number of		Exercise Price			Value		Term
			Options		per Share			(in thousands)		(in years)
	Options outstanding at January 1, 2012		377,336		$	26.09
	Granted		45,359			51.22
	Exercised		-			-		$	-
	Forfeited or expired		-			-
	Options outstanding at December 31, 2012		422,695			28.79
	Granted		-			-
Exercised		-			-		$	-
Forfeited or expired		-1,855			60.28
Options outstanding at December 31, 2013		420,840			28.65
Granted		-			-
Assumed in Kodiak Acquisition		673,235			44.48
Exercised		-117,123			15.21		$	6,203,361
Forfeited or expired		-8,559			50.51
Options outstanding at December 31, 2014		968,393		$	41.09		$	5,216,952	4.8
Options vested and expected to vest at December 31, 2014		905,107		$	40.78		$	4,984,431	4.8
Options exercisable at December 31, 2014		831,220		$	38.45		$	5,216,952	4.2
Unrecognized compensation cost as of December 31, 2014 related to unvested stock option awards was $1 million, which is expected to be recognized over a period of 1.2 years.
Rights Agreement—In 2006, the Board of Directors of the Company declared a dividend of one preferred share purchase right (a “Right”) for each outstanding share of common stock of the Company payable to the stockholders of record as of March 2, 2006.  As a result of the two-for-one split of the Company’s common stock effective February 22, 2011, one-half of a Right is now associated with each share of common stock.  Each Right entitles the registered holder to purchase from the Company one one-hundredth of a share of Series A Junior Participating Preferred Stock, par value $0.001 per share (“Preferred Shares”), of the Company at a price of $180.00 per one one-hundredth of a Preferred Share, subject to adjustment.  If any person becomes a 15% or more stockholder of the Company, then each Right (subject to certain limitations) will entitle its holder to purchase, at the Right’s then current exercise price, a number of shares of common stock of the Company or of the acquirer having a market value at the time of twice the Right’s per share exercise price.  The Company’s Board of Directors may redeem the Rights for $0.001 per Right at any time prior to the time when the Rights become exercisable.  Unless the Rights are redeemed, exchanged or terminated earlier, they will expire on February 23, 2016.
Noncontrolling Interest—The noncontrolling interest represents an unrelated third party’s 25% ownership interest in Sustainable Water Resources, LLC.  The table below summarizes the activity for the equity attributable to the noncontrolling interest (in thousands):
		Year Ended
		December 31,
		2014			2013
Balance at January 1		$	8,132		$	8,184
Net loss			-62			-52
Balance at December 31		$	8,070		$	8,132

INCOME_TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2014
INCOME TAXES [Abstract]
INCOME TAXES	10.         INCOME TAXES
	Income tax expense consists of the following (in thousands):
		Year Ended December 31,
		2014		2013		2012
	Current income tax expense (refund):
	Federal	$	-2,758	$	7,060	$	-
	State		5,383		-6,074		-669
	Total current income tax expense (refund)		2,625		986		-669
	Deferred income tax expense:
	Federal		65,522		196,787		233,468
	State		11,023		8,095		15,113
	Total deferred income tax expense		76,545		204,882		248,581
	Total	$	79,170	$	205,868	$	247,912
	Income tax expense differed from amounts that would result from applying the U.S. statutory income tax rate (35%) to income before income taxes as follows (in thousands):
		Year Ended December 31,
		2014		2013		2012
	U.S. statutory income tax expense	$	50,371	$	200,155	$	231,704
	State income taxes, net of federal benefit		12,705		13,962		14,444
	State income tax credits		-		-10,525		-
	Statutory depletion		-618		-796		-620
	Enacted changes in state tax laws		3,700		-1,416		-
	Market-based equity awards		2,805		-		-
	Permanent items		3,504		2,122		1,524
	Transaction costs		6,936		-		-
	Other		-233		2,366		860
	Total	$	79,170	$	205,868	$	247,912
	The principal components of the Company’s deferred income tax assets and liabilities at December 31, 2014 and 2013 were as follows (in thousands):
		Year Ended December 31,
		2014		2013
	Deferred income tax assets:
	Net operating loss carryforward	$	588,330	$	438,922
	Production Participation Plan liability		26,942		32,245
	Tax sharing liability		-		9,439
	Asset retirement obligations		13,791		23,642
	Underwriter fees		14,065		10,974
	Restricted stock compensation		15,527		13,384
	Premium on Senior Notes		7,979		-
	EOR credit carryforwards		7,946		7,946
	Alternative minimum tax credit carryforwards		15,694		18,452
	Transaction costs		7,957		-
	Other		9,493		3,234
	Total deferred income tax assets		707,724		558,238
	Less valuation allowance		-5,638		-1,230
	Net deferred income tax assets		702,086		557,008
	Deferred income tax liabilities:
	Oil and gas properties		1,785,926		1,675,916
	Trust distributions		129,437		149,332
	Derivative instruments		64,898		10,438
	Total deferred income tax liabilities		1,980,261		1,835,686
	Total net deferred income tax liabilities	$	1,278,175	$	1,278,678
	As of December 31, 2014, the Company had federal net operating loss (“NOL”) carryforwards of $1.7 billion.  Of this amount, $70 million in NOL carryforwards relate to tax deductions for stock compensation that exceed stock compensation costs recognized for financial statement purposes.  The benefit of these excess tax deductions will not be recognized as an NOL in the Company’s financial statements, until the related deductions reduce taxes payable and are thereby realized.  In addition, $170 million of NOL carryforwards are a result of the Kodiak Acquisition, and the utilization of this amount is limited to $77 million each year for the next three years.  The Company also has various state NOL carryforwards.  The determination of the state NOL carryforwards is dependent upon apportionment percentages and state laws that can change from year to year and that can thereby impact the amount of such carryforwards.  If unutilized, the federal NOL will expire between 2028 and 2035, and the state NOLs will expire between 2015 and 2035.
	EOR credits are a credit against federal income taxes for certain costs related to extracting high-cost oil, utilizing certain prescribed enhanced tertiary recovery methods.  As of December 31, 2014, the Company had recognized aggregate EOR credits of $8  million that are available to offset regular federal income taxes in the future.  These credits can be carried forward and will expire between 2023 and 2025.  Federal EOR credits are subject to phase-out according to the level of average domestic crude oil prices.  The EOR credit has been phased-out since 2006, but this phase-out affects only the periods for which EOR credits can be captured and not the periods in which such credits can be utilized.
	The Company is subject to the alternative minimum tax (“AMT”) principally due to its significant intangible drilling cost deductions.  As of December 31, 2014, the Company had AMT credits totaling $16 million that are available to offset future regular federal income taxes.  These credits do not expire and can be carried forward indefinitely.
	At December 31, 2014, the Company had a valuation allowance totaling $6 million, comprised of unamortized underwriter fees in Canada and foreign tax credit carryforwards, which will expire between 2015 and 2016.  These valuation allowances have been recorded because the Company determined it was more likely than not that the benefit from these deferred tax assets will not be realized due to the divestiture of all foreign operations.
	In conjunction with the Kodiak Acquisition, the Company acquired Kodiak, which is a Canadian entity that is to be disregarded for U.S. tax purposes.  Kodiak holds an interest in Whiting Resources Corporation (formerly Kodiak Oil & Gas (USA) Inc.), a U.S. entity which has undistributed earnings at December 31, 2014.  These earnings are considered to be indefinitely reinvested, and accordingly, no provision has been provided for on those earnings.  If the Company were to repatriate those earnings in the form of dividends or otherwise, no taxes would result.
	Net deferred income tax liabilities were classified in the consolidated balance sheets as follows (in thousands):
		Year Ended December 31,
		2014		2013
	Assets:
	Current deferred income taxes	$	-	$	-
	Liabilities:
	Current deferred income taxes		47,545		648
	Non-current deferred income taxes		1,230,630		1,278,030
	Net deferred income tax liabilities	$	1,278,175	$	1,278,678
The following table summarizes the activity related to the Company’s liability for unrecognized tax benefits (in thousands):
	Year Ended December 31,
	2014		2013		2012
Beginning balance at January 1	$	170	$	170	$	299
Decrease related to tax position taken in a prior period		-		-		-129
Ending balance at December 31	$	170	$	170	$	170
The unrecognized tax benefit balance at December 31, 2014 includes certain tax positions, the allowance of which would positively affect the annual effective income tax rate.  For the year ended December 31, 2014, the Company did not recognize any interest or penalties with respect to unrecognized tax benefits, nor did the Company have any such interest or penalties previously accrued.  The Company believes that it is reasonably possible that no increases or decreases to unrecognized tax benefits will occur in the next twelve months.
The Company files income tax returns in the U.S. federal jurisdiction and in various states, each with varying statutes of limitations.  The 2011 through 2014 tax years generally remain subject to examination by federal and state tax authorities.  Additionally, in conjunction with the Kodiak Acquisition, the Company has Canadian income tax filings which remain subject to examination by the related tax authorities for the 2009 through 2014 tax years.

EARNINGS_PER_SHARE

EARNINGS PER SHARE	12 Months Ended
	Dec. 31, 2014
EARNINGS PER SHARE [Abstract]
EARNINGS PER SHARE	11.         EARNINGS PER SHARE
	The reconciliations between basic and diluted earnings per share are as follows (in thousands, except per share data):
			Year Ended
			December 31,
			2014		2013		2012
	Basic Earnings Per Share
	Numerator:
	Net income available to shareholders		$	64,807	$	366,055	$	414,189
	Preferred stock dividends (1)			-		-494		-1,077
	Net income available to common shareholders, basic		$	64,807	$	365,561	$	413,112
	Denominator:
	Weighted average shares outstanding, basic			122,138		118,260		117,601
	Diluted Earnings Per Share
	Numerator:
	Net income available to common shareholders, basic		$	64,807	$	365,561	$	413,112
	Preferred stock dividends			-		538		1,077
	Adjusted net income available to common shareholders, diluted		$	64,807	$	366,099	$	414,189
	Denominator:
	Weighted average shares outstanding, basic			122,138		118,260		117,601
	Restricted stock and stock options			381		957		633
	Convertible perpetual preferred stock			-		371		794
	Weighted average shares outstanding, diluted			122,519		119,588		119,028
	Earnings per common share, basic		$	0.53	$	3.09	$	3.51
	Earnings per common share, diluted		$	0.53	$	3.06	$	3.48
	_____________________
		-1		For the year ended December 31, 2013, amount includes a decrease of $0.04 million in preferred stock dividends for preferred stock dividends accumulated.  There were no accumulated dividend adjustments for the years ended December 31, 2014 or 2012.
	For the year ended December 31, 2014, the diluted earnings per share calculation excludes (i) the dilutive effect of 803,902 incremental shares of restricted stock that did not meet its market-based vesting criteria as of December 31, 2014, and (ii) the anti-dilutive effect of 791 common shares for stock options that were out-of-the-money.  For the year ended December 31, 2013, the diluted earnings per share calculation excludes the dilutive effect of (i) 173,778 incremental shares of restricted stock that did not meet its market-based vesting criteria as of December 31, 2013, and (ii) 8,689 common shares for stock options that were out-of-the-money.  For the year ended December 31, 2012, the diluted earnings per share calculation excludes (i) the dilutive effect of 141,807 incremental shares of restricted stock that did not meet its market-based vesting criteria as of December 31, 2012, and (ii) the anti-dilutive effect of 7,720 common shares for stock options that were out-of-the-money.

RELATED_PARTY_TRANSACTIONS

RELATED PARTY TRANSACTIONS	12 Months Ended
	Dec. 31, 2014
RELATED PARTY TRANSACTIONS [Abstract]
RELATED PARTY TRANSACTIONS	12.         RELATED PARTY TRANSACTIONS
	Whiting USA Trust I—As a result of Whiting’s retained ownership of 15.8%, or 2,186,389 units in Whiting USA Trust I, it is a related party of the Company.  The following table summarizes the related party receivable and payable balances between the Company and Trust I as of December 31, 2014 and 2013 (in thousands):
			December 31,
			2014		2013
	Assets
	Unit distributions due from Trust I (1)		$	652	$	1,093
	Liabilities
	Unit distributions payable to Trust I (2)		$	4,133	$	6,932
	_____________________
		-1		This amount represents Whiting’s 15.8% interest in the net proceeds due from Trust I and is included within accounts receivable trade, net in the Company’s consolidated balance sheets.
		-2		This amount represents net proceeds from Trust I’s underlying properties that the Company has received between the last Trust I distribution date and December 31, 2014 and 2013, respectively, but which the Company has not yet distributed to Trust I as of December 31, 2014 and 2013, respectively.  Due to ongoing processing of Trust I revenues and expenses after December 31, 2014 and 2013, the amount of Whiting’s next scheduled distribution to Trust I, and the related distribution by Trust I to its unitholders, will differ from this amount.  These amounts are included within accounts payable trade in the Company’s consolidated balance sheet.
	For the year ended December 31, 2014, Whiting paid $30 million, net of state tax withholdings, in unit distributions to Trust I and received $5 million in distributions back from Trust I pursuant to its retained ownership in 2,186,389 Trust I units.
	On January 28, 2015, the net profits interest that Whiting conveyed to Trust I terminated as a result of 9.11 MMBOE (which amount is equivalent to 8.20 MMBOE attributable to the net profits interest) having been produced and sold from the underlying properties.  Upon termination, the net profits interest in the underlying properties reverted back to Whiting, and Trust I will no longer be a related party.
	Tax Sharing Liability—Prior to Whiting’s initial public offering in November 2003, it was a wholly-owned indirect subsidiary of Alliant Energy Corporation (“Alliant Energy”), and when the transactions discussed below were entered into, Alliant Energy was a related party of the Company.  As of December 31, 2004 and thereafter, Alliant Energy was no longer a related party.
	In 2003, the Company entered into a Tax Separation and Indemnification Agreement with Alliant Energy, whereby the Company and Alliant Energy made certain tax elections with the effect that the tax bases of Whiting’s assets were increased. Such additional tax bases have resulted in increased income tax deductions for Whiting and, accordingly, have reduced income taxes otherwise payable by Whiting.  Under this Tax Separation and Indemnification Agreement, the Company agreed to pay to Alliant Energy (each year from 2004 to 2013) 90% of the tax benefits the Company realized annually as a result of this step-up in tax bases.  In 2014, Whiting was obligated to pay Alliant the present value of 90% of the remaining tax benefits expected to result from its increased tax bases, which payout assumes all such tax benefits will be realized in future years.
	In March 2014, the Company made the final payment due Alliant Energy under this agreement totaling $26 million, including $3 million of interest.  During 2013 and 2012, the Company made payments of $2 million each year under this agreement and recognized interest expense of $3 million and $2 million, respectively.
	Alliant Energy Guarantee—The Company holds a 6% working interest in three offshore platforms in California and the related onshore plant and equipment.  Alliant Energy has guaranteed the Company’s obligation in the abandonment of these assets.

COMMITMENTS_AND_CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	12 Months Ended
	Dec. 31, 2014
COMMITMENTS AND CONTINGENCIES [Abstract]
COMMITMENTS AND CONTINGENCIES	13.         COMMITMENTS AND CONTINGENCIES
	The table below shows the Company’s minimum future payments under non-cancelable operating leases and unconditional purchase obligations as of December 31, 2014 (in thousands):
		Payments due by period
		2015		2016		2017		2018		2019		Thereafter		Total
	Non-cancelable leases	$	7,692	$	7,547	$	6,610	$	6,693	$	5,844	$	216	$	34,602
	Drilling rig contracts		146,141		101,855		30,788		-		-		-		278,784
	Pipeline transportation agreements		5,948		9,722		9,559		9,559		9,559		50,091		94,438
	Total	$	159,781	$	119,124	$	46,957	$	16,252	$	15,403	$	50,307	$	407,824
	Non-cancelable Leases—The Company leases 197,000 square feet of administrative office space in Denver, Colorado under an operating lease arrangement expiring in 2019,  47,900 square feet of office space in Midland, Texas expiring in 2020, an additional 36,300 square feet of administrative office space in Denver, Colorado assumed in the Kodiak Acquisition expiring in 2016, and 20,000 square feet of office space in Dickinson, North Dakota expiring in 2016.  In addition, the Company entered into a lease for several residential apartments in Watford City and Dickinson, North Dakota under an operating lease arrangement expiring in 2015.  Rental expense for 2014, 2013 and 2012 amounted to $7 million, $5 million and $6 million, respectively.  Minimum lease payments under the terms of non-cancelable operating leases as of December 31, 2014 are shown in the table above.
	Drilling Rig Contracts—As of December 31, 2014, the Company had 18 drilling rigs under long-term contract, all of which were operating in the Rocky Mountains region.  Subsequent to December 31, 2014, the Company early terminated five of these long-term contracts incurring early termination penalties totaling approximately $27 million.  These penalties and the Company’s minimum drilling commitments under the terms of the 18 long-term drilling rig contracts as of December 31, 2014 are shown in the table above.  Of the remaining 13 long-term contracts, seven expire in 2016 and six in 2017.  Early termination of the remaining contracts would require termination penalties of $212 million, which would be in lieu of paying the remaining drilling commitments under these contracts.  No other drilling rigs working for the Company are currently under long-term contracts or contracts that cannot be terminated at the end of the well that is currently being drilled.  During 2014, 2013 and 2012, the Company made payments of $106 million, $93 million and $101 million, respectively, under these long-term contracts, which are initially capitalized as a component of oil and gas properties and either depleted in future periods or written off as exploration expense.
	Pipeline Transportation Agreements—The Company has two ship-or-pay agreements with different suppliers,  one expiring in 2015 and one expiring in 2017, whereby it has committed to transport a minimum daily volume of CO2 or water, as the case may be, via certain pipelines or else pay for any deficiencies at a price stipulated in the contracts.    Although minimum daily quantities are specified in the agreements, the actual CO2 or water volumes transported and their corresponding unit prices are variable over the term of the contracts.  As a result, the future minimum payments for each of the five succeeding fiscal years are not fixed and determinable and are not therefore included in the table above.  As of December 31, 2014, the Company estimated future commitments under these ship-or-pay agreements to approximate $20 million through 2017.
	In addition, the Company has three pipeline transportation agreements, one expiring in 2024 and two expiring in 2025, whereby it has committed to pay monthly reservation fees on dedicated pipelines for natural gas and NGL transportation capacity from the Redtail field, plus a variable charge based on actual transportation volumes.  These fixed monthly reservation fees totaling approximately $94 million have been included in the table above.
	During 2014, 2013 and 2012, transportation of natural gas, CO2 and water under these contracts amounted to $13 million, $4 million and $3 million, respectively.  As of December 31, 2014, the Company estimated future commitments under all of these pipeline transportation agreements to approximate $114 million through 2025.
	Purchase Contracts—The Company has three take-or-pay purchase agreements, of which one agreement expires in 2015 and two agreements expire in 2017.  One of these agreements contains commitments to buy certain volumes of CO2 for use in its EOR project in the North Ward Estes field in Texas.  Under the remaining two take-or-pay agreements, the Company has committed to buy certain volumes of water for use in the fracture stimulation process of wells in its Redtail field. Under the terms of these agreements, the Company is obligated to purchase a minimum volume of CO2 or water, as the case may be, or else pay for any deficiencies at the price stipulated in the contract.  The CO2 volumes planned for use in the Company’s EOR project in the North Ward Estes field and the water volumes planned for use at our Redtail field currently exceed the minimum volumes specified in all of these agreements, therefore, the Company expects to avoid any payments for deficiencies under these contracts.  During 2014, 2013 and 2012, purchases of CO2 and water amounted to $105 million, $84 million and $83 million, respectively.  Although minimum daily quantities are specified in the agreements, the actual CO2 or water volumes purchased and their corresponding unit prices are variable over the term of the contracts.  As a result, the future minimum payments for each of the five succeeding fiscal years are not fixed and determinable and are not therefore included in the table above.  As of December 31, 2014, the Company estimated future commitments under all of these purchase agreements to approximate $149 million through 2017.
	Delivery Commitments—The Company has various physical delivery contracts which require the Company to deliver fixed volumes of crude oil.  As of December 31, 2014, the Company had delivery commitments of 12.4 MMBbl, 17.8 MMBbl, 19.6 MMBbl, 21.5 MMBbl, 23.3 MMBbl and 6.0 MMBbl of crude oil for the years ended December 31, 2015 through 2020, respectively.  These delivery commitments relate to crude oil production at Whiting’s Redtail field in the DJ Basin in Weld County, Colorado.  As of December 31, 2014, the Company determined that it is no longer probable that future oil production from its Redtail field will be sufficient to meet the minimum volume requirements specified in these physical delivery contracts, and as a result, the Company expects to make periodic deficiency payments for any shortfalls in delivering the minimum committed volumes.  The Company currently anticipates that it will under-deliver by a total of approximately 10.4 MMBbl over the duration of the contracts, which would require undiscounted aggregate deficiency payments of approximately $49 million over the next 5 years.  The Company recognizes any monthly deficiency payments in the period in which the underdelivery takes place and the related liability has been incurred.  The table above does not include any such deficiency payments that may be incurred under the Company’s physical delivery contracts, since it cannot be predicted with accuracy the amount and timing of any such penalties incurred.
	Litigation—The Company is subject to litigation, claims and governmental and regulatory proceedings arising in the ordinary course of business.  We accrue a loss contingency for these lawsuits and claims when it is probable that a loss has been incurred and the amount of the loss can be reasonably estimated.  Accordingly, no material amounts for loss contingencies associated with litigation, claims or assessments have been accrued at December 31, 2014 or 2013.  While the outcome of these lawsuits and claims cannot be predicted with certainty, it is the opinion of the Company’s management that the loss for any litigation matters and claims that are reasonably possible to occur will not have a material adverse effect, individually or in the aggregate, on its consolidated financial position, cash flows or results of operations.

SUBSEQUENT_EVENT

SUBSEQUENT EVENT	12 Months Ended
	Dec. 31, 2014
SUBSEQUENT EVENT [Abstract]
SUBSEQUENT EVENT	14.         SUBSEQUENT EVENT
	On January 7, 2015, as required under the Kodiak Indentures upon a change in control, Whiting offered to repurchase at 101% of par all $1,550 million principal amount of Kodiak Notes outstanding.  The repurchase offer expires on March 3, 2015.  The Company expects to fund any payments due as a result of such repurchase offer with borrowings under its revolving credit facility.

OIL_AND_GAS_ACTIVITIES

OIL AND GAS ACTIVITIES	12 Months Ended
	Dec. 31, 2014
OIL AND GAS ACTIVITIES [Abstract]
OIL AND GAS ACTIVITIES	15.         OIL AND GAS ACTIVITIES
	The Company’s oil and gas activities for 2014, 2013 and 2012 were entirely within the United States.  Costs incurred in oil and gas producing activities were as follows (in thousands):
			Year Ended December 31,
			2014		2013		2012
	Development (1)		$	2,891,893	$	2,132,824	$	1,667,182
	Proved property acquisition (2)			2,278,855		232,572		19,785
	Unproved property acquisition (2)			1,035,439		174,103		119,175
	Exploration			216,587		363,234		436,084
	Total		$	6,422,774	$	2,902,733	$	2,242,226
	_____________________
		-1		During 2014, 2013 and 2012, non-cash additions to oil and gas properties of $45 million, $30 million and $36 million, respectively, which relate to estimated costs of the future plugging and abandonment of the Company’s oil and gas wells, are included in development costs in the table above.
		-2		During 2014, amounts include $2.3 billion of non-cash proved property additions and $1.0 billion of non-cash unproved property additions related to the Kodiak Acquisition.
	Net capitalized costs related to the Company’s oil and gas producing activities were as follows (in thousands):
			Year Ended December 31,
			2014		2013
	Proved oil and gas properties		$	12,956,834	$	9,196,845
	Unproved oil and gas properties			1,992,868		868,305
	Accumulated depletion			-3,003,270		-2,645,841
	Oil and gas properties, net		$	11,946,432	$	7,419,309
	Exploratory well costs that are incurred and expensed in the same annual period have not been included in the table below.  The net changes in capitalized exploratory well costs were as follows (in thousands):
			Year Ended December 31,
			2014		2013		2012
	Beginning balance at January 1		$	85,378	$	108,861	$	90,519
	Additions to capitalized exploratory well costs pending the determination of proved reserves			145,336		281,951		384,223
	Reclassifications to wells, facilities and equipment based on the determination of proved reserves			-200,869		-291,962		-358,625
	Capitalized exploratory well costs charged to expense			-15,552		-13,472		-7,256
	Ending balance at December 31		$	14,293	$	85,378	$	108,861
	At December 31, 2014, the Company had no costs capitalized for exploratory wells in progress for a period of greater than one year  after the completion of drilling.

DISCLOSURES_ABOUT_OIL_AND_GAS_

DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES	12 Months Ended
	Dec. 31, 2014
DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES [Abstract]
DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES	16.         DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
	For all years presented our independent petroleum engineers independently estimated all of the proved, probable and possible reserve quantities included in this annual report.  In connection with our external petroleum engineers performing their independent reserve estimations, we furnish them with the following information that they review: (1) technical support data, (2) technical analysis of geologic and engineering support information, (3) economic and production data and (4) our well ownership interests.  The independent petroleum engineers, Cawley, Gillespie & Associates, Inc., evaluated 100% of our estimated proved reserve quantities and their related pre-tax future net cash flows as of December 31, 2014.  Proved reserve estimates included herein conform to the definitions prescribed by the SEC.  Estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors.
	As of December 31, 2014, all of the Company’s oil and gas reserves are attributable to properties within the United States.  A summary of the Company’s changes in quantities of proved oil and gas reserves for the years ended December 31, 2012, 2013 and 2014 are as follows:
			Oil		NGLs		Natural Gas	Total
			(MBbl)		(MBbl)		(MMcf)	(MBOE)
	Balance—January 1, 2012		260,144		37,609		284,975	345,249
	Extensions and discoveries		68,134		6,526		40,915	81,479
	Sales of minerals in place		-7,960		-320		-13,987	-10,611
	Production		-23,139		-2,766		-25,827	-30,209
	Revisions to previous estimates		4,106		-951		-61,812	-7,148
	Balance—December 31, 2012		301,285		40,098		224,264	378,760
	Extensions and discoveries		88,293		9,830		63,893	108,772
	Sales of minerals in place		-36,992		-4,777		-12,411	-43,838
	Purchases of minerals in place		14,543		1,311		7,751	17,146
	Production		-27,035		-2,821		-26,917	-34,342
	Revisions to previous estimates		7,327		1,228		20,934	12,044
	Balance—December 31, 2013		347,421		44,869		277,514	438,542
	Extensions and discoveries		146,122		12,947		94,452	174,811
	Sales of minerals in place		-1,642		-		-2,925	-2,130
	Purchases of minerals in place		169,586		-		156,140	195,609
	Production		-33,485		-3,283		-30,218	-41,804
	Revisions to previous estimates		15,627		151		-2,943	15,288
	Balance—December 31, 2014		643,629		54,684		492,020	780,316
	Proved developed reserves:
	31-Dec-11		180,975		22,109		211,297	238,300
	31-Dec-12		190,845		24,204		160,893	241,864
	31-Dec-13		198,204		23,721		183,129	252,446
	31-Dec-14		333,593		28,935		298,237	412,234
	Proved undeveloped reserves:
	31-Dec-11		79,169		15,500		73,678	106,949
	31-Dec-12		110,440		15,894		63,371	136,896
	31-Dec-13		149,217		21,148		94,385	186,096
	31-Dec-14		310,036		25,749		193,783	368,082
	Notable changes in proved reserves for the year ended December 31, 2014 included:
		·		Extensions and discoveries.  In 2014, total extensions and discoveries of 174.8 MMBOE were primarily attributable to successful drilling at the Redtail, Sanish, Hidden Bench, Missouri Breaks, Pronghorn, Tarpon and Cassandra fields.  Both the new wells drilled in these areas as well as the PUD locations added as a result of drilling increased the Company’s proved reserves.
		·		Sales of minerals in place.  In 2014, total sales of minerals in place of 2.1 MMBOE were primarily attributable to the disposition of properties in the Big Tex prospect, further described in the Acquisitions and Divestitures footnote, as well as other property divestitures in the Lucky Ditch, Whiskey Springs and Bridger Lake fields, which decreased the Company’s proved reserves.
		·		Purchases of minerals in place.  In 2014, total purchases of minerals in place of 195.6 MMBOE were primarily attributable to the Kodiak Acquisition, whereby we acquired interests in 778 producing oil and gas wells and undeveloped acreage in the Williston Basin, further described in the Acquisitions and Divestitures footnote, which increased the Company’s proved reserves.
		·		Revisions to previous estimates.  In 2014, revisions to previous estimates increased proved developed and undeveloped reserves by a net amount of 15.3 MMBOE.  Included in these revisions were (i) 15.6 MMBOE of net upward adjustments attributable to reservoir analysis and well performance and (ii) 0.3 MMBOE of downward adjustments caused by lower crude oil prices incorporated into the Company’s reserve estimates at December 31, 2014 as compared to December 31, 2013.
	Notable changes in proved reserves for the year ended December 31, 2013 included:
		·		Extensions and discoveries.  In 2013, total extensions and discoveries of 108.8 MMBOE were primarily attributable to successful drilling in the Redtail, Sanish, Missouri Breaks, Hidden Bench and Pronghorn fields.  The new producing wells in these areas and their related proved undeveloped locations added during the year increased the Company’s proved reserves.
		·		Sales of minerals in place.  In 2013, total sales of minerals in place of 43.8 MMBOE were primarily attributable to the disposition of the Postle Properties, further described in the Acquisitions and Divestitures footnote, which decreased the Company’s proved reserves.
		·		Purchases of minerals in place.  In 2013, total purchases of minerals in place of 17.1 MMBOE were primarily attributable to the acquisition of 121 producing oil and gas wells and undeveloped acreage in the Williston Basin, further described in the Acquisitions and Divestitures footnote, which increased the Company’s proved reserves.
		·		Revisions to previous estimates.  In 2013, revisions to previous estimates increased proved developed and undeveloped reserves by a net amount of 12.0 MMBOE.  Included in these revisions were (i) 4.9 MMBOE of upward adjustments caused by higher crude oil and natural gas prices incorporated into the Company’s reserve estimates at December 31, 2013 as compared to December 31, 2012 and (ii) 7.1 MMBOE of net upward adjustments attributable to reservoir analysis and well performance.
	Notable changes in proved reserves for the year ended December 31, 2012 included:
		·		Extensions and discoveries.  In 2012, total extensions and discoveries of 81.5 MMBOE were primarily attributable to successful drilling in the Sanish, Redtail, Missouri Breaks and Pronghorn fields.  The new producing wells in these fields and their related proved undeveloped locations added during the year increased the Company’s proved reserves.
		·		Revisions to previous estimates.  In 2012, revisions to previous estimates decreased proved developed and undeveloped reserves by a net amount of 7.1 MMBOE.  Included in these revisions were (i) 11.8 MMBOE of downward adjustments caused by lower crude oil and natural gas prices incorporated into the Company’s reserve estimates at December 31, 2012 as compared to December 31, 2011, and (ii) 4.7 MMBOE of net upward adjustments attributable to reservoir analysis and well performance.
	As discussed in Deferred Compensation within these footnotes to the consolidated financial statements, the Company had a Production Participation Plan (the “Plan”) in which all employees participated.  On June 11, 2014, the Board of Directors of the Company terminated the Plan effective December 31, 2013.  The reserve disclosures above include oil and natural gas reserve volumes that were allocated to the Plan prior to its termination.  Once allocated to Plan participants, the interests were fixed.  Interest allocations prior to 1995 consisted of 2%–3% overriding royalty interests.  Interest allocations after 1995 were 1.75%–5% of oil and gas sales less lease operating expenses and production taxes from the production allocated to the Plan.
	The standardized measure of discounted future net cash flows relating to proved oil and gas reserves and the changes in standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves were prepared in accordance with the provisions of FASB ASC Topic 932, Extractive Activities—Oil and Gas.  Future cash inflows as of December 31, 2014, 2013 and 2012 were computed by applying average fiscal-year prices (calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period ended December 31, 2014, 2013 and 2012, respectively) to estimated future production.  Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves at year end, based on year-end costs and assuming the continuation of existing economic conditions.
	Future income tax expenses are calculated by applying appropriate year-end tax rates to future pretax net cash flows relating to proved oil and natural gas reserves, less the tax basis of properties involved.  Future income tax expenses give effect to permanent differences, tax credits and loss carryforwards relating to the proved oil and natural gas reserves.  Future net cash flows are discounted at a rate of 10% annually to derive the standardized measure of discounted future net cash flows.  This calculation does not necessarily result in an estimate of the fair value of the Company’s oil and gas properties.
	The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is as follows (in thousands):
			December 31,
			2014			2013		2012
	Future cash flows		$	59,949,707		$	35,178,399	$	29,308,752
	Future production costs			-20,772,234			-12,973,292		-11,397,332
	Future development costs			-7,924,573			-5,355,383		-3,181,618
	Future income tax expense			-8,579,237			-3,954,401		-4,278,529
	Future net cash flows			22,673,663			12,895,323		10,451,273
	10% annual discount for estimated timing of cash flows			-11,830,243			-6,301,462		-5,044,240
	Standardized measure of discounted future net cash flows		$	10,843,420		$	6,593,861	$	5,407,033
	Future cash flows as shown above are reported without consideration for the effects of open hedge contracts at each period end.  If the effects of hedging transactions were included in the computation, then undiscounted future cash inflows would have decreased by $7 million in 2014, would not have changed in 2013 and would have decreased by $20 million in 2012.
	The changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows (in thousands):
			December 31,
			2014			2013		2012
	Beginning of year		$	6,593,861		$	5,407,033	$	5,272,492
Sale of oil and gas produced, net of production costs			-2,274,682			-2,010,925		-1,589,665
Sales of minerals in place			-48,532			-1,064,195		-438,614
Net changes in prices and production costs			81,522			902,916		-1,061,495
Extensions, discoveries and improved recoveries			3,950,413			2,827,321		3,708,780
Previously estimated development costs incurred during the period			1,149,926			832,096		526,982
Changes in estimated future development costs			-3,382,849			-1,264,189		-1,498,592
Purchases of minerals in place			4,420,417			445,669		-
Revisions of previous quantity estimates			345,775			313,069		-295,432
Net change in income taxes			-651,817			-335,637		255,328
Accretion of discount			659,386			540,703		527,249
End of year		$	10,843,420		$	6,593,861	$	5,407,033
Future net revenues included in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves incorporate calculated weighted average sales prices (inclusive of adjustments for quality and location) in effect at December 31, 2014, 2013 and 2012 as follows:
		2014			2013		2012
Oil (per Bbl)		$	84.69		$	90.8	$	87.15
NGLs (per Bbl)		$	46.59		$	54.38	$	58.15
Natural Gas (per Mcf)		$	5.88		$	4.3	$	3.21

QUARTERLY_FINANCIAL_DATA

QUARTERLY FINANCIAL DATA	12 Months Ended
	Dec. 31, 2014
QUARTERLY FINANCIAL DATA [Abstract]
QUARTERLY FINANCIAL DATA	17.         QUARTERLY FINANCIAL DATA (UNAUDITED)
	The following is a summary of the unaudited quarterly financial data for the years ended December 31, 2014 and 2013 (in thousands, except per share data):
			Three Months Ended
			March 31,		June 30,		September 30,		December 31,
			2014		2014		2014		2014
	Oil, NGL and natural gas sales		$	721,250	$	825,760	$	805,054	$	672,553
	Operating profit (1)		$	311,169	$	370,033	$	326,215	$	177,722
	Net income (loss)		$	109,051	$	151,426	$	157,961	$	-353,693
	Basic earnings (loss) per share		$	0.92	$	1.27	$	1.33	$	-2.69
	Diluted earnings (loss) per share		$	0.91	$	1.26	$	1.32	$	-2.68
			Three Months Ended
			March 31,		June 30,		September 30,		December 31,
			2013		2013		2013		2013
	Oil, NGL and natural gas sales		$	605,114	$	651,868	$	706,543	$	703,024
	Operating profit (1)		$	252,806	$	269,528	$	316,764	$	280,311
	Net income (loss)		$	86,244	$	134,944	$	204,091	$	-59,276
	Basic earnings (loss) per share		$	0.73	$	1.14	$	1.72	$	-0.5
	Diluted earnings (loss) per share		$	0.72	$	1.14	$	1.71	$	-0.5
	_____________________
		-1		Oil, NGL and natural gas sales less lease operating expense, production taxes and depreciation, depletion and amortization.

SCHEDULE_I_CONDENSED_FINANCIAL

SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT	12 Months Ended
	Dec. 31, 2014
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT [Abstract]
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT	SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT
	WHITING PETROLEUM CORPORATION
	CONDENSED FINANCIAL STATEMENTS OF THE PARENT COMPANY
	CONDENSED BALANCE SHEETS
	(in thousands)
		December 31,
		2014		2013
	ASSETS
	Current assets	$	3,859	$	5,120
	Investment in subsidiaries		5,464,763		2,707,184
	Intercompany receivable		2,907,270		3,796,321
	Total assets	$	8,375,892	$	6,508,625
	LIABILITIES AND EQUITY
	Current liabilities	$	27,738	$	26,054
	Long-term debt		2,653,180		2,653,834
	Other long-term liabilities		-		170
	Shareholders’ equity		5,694,974		3,828,567
	Total liabilities and equity	$	8,375,892	$	6,508,625
	CONDENSED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
	(in thousands)
		Year Ended December 31,
		2014		2013		2012
	OPERATING EXPENSES:
	General and administrative	$	-1,010	$	-1,131	$	-16,506
	Interest expense		-1,864		-2,922		-2,168
	Equity in earnings of subsidiaries		66,100		361,732		425,870
	INCOME BEFORE INCOME TAXES		63,226		357,679		407,196
	Income tax benefit		1,581		8,376		6,993
	NET INCOME	$	64,807	$	366,055	$	414,189
	COMPREHENSIVE INCOME	$	64,807	$	366,055	$	414,189
	See notes to condensed financial statements.
	Schedule I
	WHITING PETROLEUM CORPORATION
	CONDENSED FINANCIAL STATEMENTS OF THE PARENT COMPANY
	CONDENSED STATEMENTS OF CASH FLOWS
	(in thousands)
		Year Ended December 31,
		2014		2013		2012
	CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	-	$	-	$	16,423
	CASH FLOWS FROM INVESTING ACTIVITIES:
	Investment in subsidiaries		-		-		-
	CASH FLOWS FROM FINANCING ACTIVITIES:
	Intercompany receivable		26,373		-2,048,253		-14,094
	Issuance of 5% Senior Notes due 2019		-		1,100,000		-
	Issuance of 5.75% Senior Notes due 2021		-		1,204,000		-
	Redemption of 7% Senior Subordinated Notes due 2014		-		-253,988		-
	Repayment of tax sharing liability		-26,373		-1,759		-2,329
	Net cash used in financing activities		-		-		-16,423
	NET CHANGE IN CASH AND CASH EQUIVALENTS		-		-		-
	CASH AND CASH EQUIVALENTS:
	Beginning of period		-		-		-
	End of period	$	-	$	-	$	-
	NONCASH INVESTING AND FINANCING ACTIVITIES:
	Fair value of equity issued in the Kodiak Acquisition	$	2,696,094	$	-	$	-
	Distributions from Whiting USA Trust I	$	4,614	$	4,749	$	5,827
	Preferred stock dividends paid	$	-	$	-538	$	-1,077
	See notes to condensed financial statements.
	WHITING PETROLEUM CORPORATION
	NOTES TO CONDENSED FINANCIAL STATEMENTS OF THE PARENT COMPANY
	1.      BASIS OF PRESENTATION
	Condensed Financial Statements—The condensed financial statements of Whiting Petroleum Corporation (the “Registrant” or “Parent Company”) do not include all of the information and notes normally included with financial statements prepared in accordance with GAAP.  These condensed financial statements, therefore, should be read in conjunction with the consolidated financial statements and notes thereto of the Registrant, included elsewhere in this Annual Report on Form 10-K.  For purposes of these condensed financial statements, the Parent Company’s investments in wholly-owned subsidiaries are accounted for under the equity method.
	Restricted Assets of Registrant—Except for limited exceptions, including the payment of interest on the senior notes and senior subordinated notes, Whiting Oil and Gas Corporation’s (“Whiting Oil and Gas”) credit agreement restricts the ability of Whiting Oil and Gas to make any dividend payments, distributions or other payments to the Parent Company.  As of December 31, 2014, total restricted net assets were $6.9 billion.  Accordingly, these condensed financial statements have been prepared pursuant to Rule 5-04 of Regulation S-X of the Securities Exchange Act of 1934, as amended.
	2.      LONG-TERM DEBT AND OTHER LONG-TERM LIABILITIES
	The Parent Company’s long-term debt and other long-term liabilities consisted of the following at December 31, 2014 and 2013 (in thousands):
	December 31,
	2014		2013
Long-term debt:
6.5% Senior Subordinated Notes due 2018	$	350,000	$	350,000
5% Senior Notes due 2019		1,100,000		1,100,000
5.75% Senior Notes due 2021, including unamortized debt premium of $3,180 and $3,834, respectively		1,203,180		1,203,834
Other long-term liabilities		-		170
Total long-term debt and other long-term liabilities	$	2,653,180	$	2,654,004
Scheduled maturities of the Parent Company’s principal amounts of long-term debt and other long-term liabilities (including the current portions thereof) as of December 31, 2014 were as follows (in thousands):
	2015		2016		2017		2018		2019		Thereafter		Total
Amounts due	$	-	$	-	$	-	$	350,000	$	1,100,000	$	1,200,000	$	2,650,000
For further information on the Senior Subordinated Notes, Senior Notes and tax sharing liability, refer to the Long-Term Debt and Related Party Transactions notes to the consolidated financial statements of the Registrant.
3.      SHAREHOLDERS’ EQUITY
6.25% Convertible Perpetual Preferred Stock—In June 2009, the Parent Company completed a public offering of 6.25% convertible perpetual preferred stock (“preferred stock”), selling 3,450,000 shares at a price of $100.00 per share.  As a result of voluntary conversions and the Parent Company exercising its right to mandatorily convert shares of preferred stock effective June 27, 2013, all 172,129 remaining shares of preferred stock outstanding on March 31, 2013, were converted into 792,919 shares of common stock.  As of December 31, 2014, no shares of preferred stock remained outstanding.
For further information on the convertible perpetual preferred stock, refer to the Shareholders’ Equity note to the consolidated financial statements of the Registrant.

SUMMARY_OF_SIGNIFICANT_ACCOUNT1

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2014
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES [Abstract]
Basis of Presentation of Consolidated Financial Statements	Basis of Presentation of Consolidated Financial Statements—The consolidated financial statements include the accounts of Whiting Petroleum Corporation, its consolidated subsidiaries and Whiting’s pro rata share of the accounts of Whiting USA Trust I (“Trust I”) pursuant to Whiting’s 15.8% ownership interest in Trust I.  Investments in entities which give Whiting significant influence, but not control, over the investee are accounted for using the equity method.  Under the equity method, investments are stated at cost plus the Company’s equity in undistributed earnings and losses.  All intercompany balances and transactions have been eliminated upon consolidation.
Use of Estimates	Use of Estimates—The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period.  Items subject to such estimates and assumptions include (1) oil and natural gas reserves; (2) cash flow estimates used in impairment tests of long-lived assets; (3) depreciation, depletion and amortization; (4) asset retirement obligations; (5) assigning fair value and allocating purchase price in connection with business combinations, including the determination of any resulting goodwill; (6) income taxes; (7) accrued liabilities; (8) valuation of derivative instruments; and (9) accrued revenue and related receivables.  Although management believes these estimates are reasonable, actual results could differ from these estimates.
Cash and Cash Equivalents	Cash and Cash Equivalents—Cash equivalents consist of demand deposits and highly liquid investments which have an original maturity of three months or less.
Accounts Receivable Trade	Accounts Receivable Trade—Whiting’s accounts receivable trade consist mainly of receivables from oil and gas purchasers and joint interest owners on properties the Company operates.  For receivables from joint interest owners, Whiting typically has the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings.  Generally, the Company’s oil and gas receivables are collected within two months, and to date, the Company has had minimal bad debts.
	The Company routinely assesses the recoverability of all material trade and other receivables to determine their collectability.  At December 31, 2014 and 2013, the Company had an allowance for doubtful accounts of $9 million and $4 million, respectively.
Inventories	Inventories—Materials and supplies inventories consist primarily of tubular goods and production equipment, carried at weighted-average cost.  Materials and supplies are included in other property and equipment.  Crude oil in tanks inventory is carried at the lower of the estimated cost to produce or market value and is included in prepaid expenses and other.
Oil and Gas Properties	Oil and Gas Properties
	Proved.  The Company follows the successful efforts method of accounting for its oil and gas properties.  Under this method of accounting, all property acquisition costs and development costs are capitalized when incurred and depleted on a units-of-production basis over the remaining life of proved reserves and proved developed reserves, respectively.  Costs of drilling exploratory wells are initially capitalized but are charged to expense if the well is determined to be unsuccessful.
	The Company assesses its proved oil and gas properties for impairment whenever events or circumstances indicate that the carrying value of the assets may not be recoverable.  The impairment test compares undiscounted future net cash flows to the assets’ net book value.  If the net capitalized costs exceed future net cash flows, then the cost of the property is written down to fair value.  Fair value for oil and gas properties is generally determined based on discounted future net cash flows.  Impairment expense for proved properties is reported in exploration and impairment expense.
	Net carrying values of retired, sold or abandoned properties that constitute less than a complete unit of depreciable property are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized in income.  Gains or losses from the disposal of complete units of depreciable property are recognized to earnings.
	Interest cost is capitalized as a component of property cost for development projects that require greater than six months to be readied for their intended use.  During 2014, 2013 and 2012, the Company capitalized interest of $4 million, $2 million and $3 million, respectively.
	Unproved.  Unproved properties consist of costs to acquire undeveloped leases as well as purchases of unproved reserves.  Undeveloped lease costs and unproved reserve acquisitions are capitalized, and individually insignificant unproved properties are amortized on a composite basis, based on past success, past experience and average lease-term lives.  The Company evaluates significant unproved properties for impairment based on remaining lease term, drilling results, reservoir performance, seismic interpretation or future plans to develop acreage.  When successful wells are drilled on undeveloped leaseholds, unproved property costs are reclassified to proved properties and depleted on a unit-of-production basis.  Impairment expense for unproved properties is reported in exploration and impairment expense.
	Exploratory.  Geological and geophysical costs, including exploratory seismic studies, and the costs of carrying and retaining unproved acreage are expensed as incurred.  Costs of seismic studies that are utilized in development drilling within an area of proved reserves are capitalized as development costs.  Amounts of seismic costs capitalized are based on only those blocks of data used in determining development well locations.  To the extent that a seismic project covers areas of both developmental and exploratory drilling, those seismic costs are proportionately allocated between development costs and exploration expense.
	Costs of drilling exploratory wells are initially capitalized, pending determination of whether the well has found proved reserves.  If an exploratory well has not found proved reserves, the costs of drilling the well and other associated costs are charged to expense.  Cost incurred for exploratory wells that find reserves, which cannot yet be classified as proved, continue to be capitalized if (a) the well has found a sufficient quantity of reserves to justify completion as a producing well, and (b) the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project.  If either condition is not met, or if the Company obtains information that raises substantial doubt about the economic or operational viability of the project, the exploratory well costs, net of any salvage value, are expensed.
	Enhanced recovery activities.  The Company carries out tertiary recovery methods on certain of its oil and gas properties in order to recover additional hydrocarbons that are not recoverable from primary or secondary recovery methods.  Acquisition costs of tertiary injectants, such as purchased CO2, for EOR activities that are used during a project’s pilot phase, or prior to a project’s technical and economic viability (i.e. prior to the recognition of proved tertiary recovery reserves) are expensed as incurred.  After a project has been determined to be technically feasible and economically viable, all acquisition costs of tertiary injectants are capitalized as development costs and depleted, as they are incurred solely for obtaining access to reserves not otherwise recoverable and have future economic benefits over the life of the project.  As CO2 is recovered together with oil and gas production, it is extracted and re-injected, and all the associated CO2 recycling costs are expensed as incurred.  Likewise costs incurred to maintain reservoir pressure are also expensed.
Other Property and Equipment	Other Property and Equipment—Other property and equipment consists of (i) materials and supplies inventories, (ii) leasehold costs and development costs of our CO2 source properties and (iii) other property and equipment including, furniture and fixtures, buildings, leasehold improvements and automobiles, which are stated at cost and depreciated using the straight-line method over their estimated useful lives ranging from 4 to 30 years.
Goodwill	Goodwill—Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in a business combination.  Goodwill has an indefinite useful life and is not amortized, but rather is tested by the Company for impairment annually in the second quarter or when events or changes in circumstances indicate that the fair value of a reporting unit has been reduced below its carrying value.  If the Company’s qualitative analysis indicates that it is more likely than not that the fair value of the reporting unit is less than its carrying value, the Company then performs a quantitative impairment test.  If the carrying value of the reporting unit exceeds its fair value, goodwill is written down to its implied fair value with an offsetting charge to earnings.
Debt Issuance Costs	Debt Issuance Costs—Debt issuance costs related to the Company’s Senior Notes and Senior Subordinated Notes are amortized to interest expense using the effective interest method over the term of the related debt.  Debt issuance costs related to the credit facility are amortized to interest expense on a straight-line basis over the borrowing term.
Derivative Instruments	Derivative Instruments—The Company enters into derivative contracts, primarily costless collars and swap contracts, to manage its exposure to commodity price risk.    All derivative instruments, other than those that meet the “normal purchase normal sale” exclusion, are recorded on the balance sheet as either an asset or liability measured at fair value.  Gains and losses from changes in the fair value of derivative instruments are recognized immediately in earnings, unless the derivative meets specific hedge accounting criteria, and the derivative has been designated as a hedge.  Effective April 1, 2009, however, the Company elected to discontinue all hedge accounting prospectively, and as of December 31, 2013, all amounts related to de-designated cash flow hedges had been reclassified into earnings.
	Cash flows from derivatives used to manage commodity price risk are classified in operating activities along with the cash flows of the underlying hedged transactions.  The Company does not enter into derivative instruments for speculative or trading purposes.
Asset Retirement Obligations and Environmental Costs	Asset Retirement Obligations and Environmental Costs—Asset retirement obligations relate to future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment and facilities from leased acreage and returning such land to its original condition.  The fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred (typically when a well is completed or acquired or an asset is installed at the production location), and the cost of such liability increases the carrying amount of the related long-lived asset by the same amount.  The liability is accreted each period through charges to depreciation, depletion and amortization expense, and the capitalized cost is depleted on a units-of-production basis over the proved developed reserves of the related asset.  Revisions to estimated retirement obligations result in adjustments to the related capitalized asset and corresponding liability.
	Liabilities for environmental costs are recorded on an undiscounted basis when it is probable that obligations have been incurred and the amounts can be reasonably estimated.  These liabilities are not reduced by possible recoveries from third parties.
Deferred Gain On Sales	Deferred Gain on Sale—The deferred gain on sale relates to the sale of 11,677,500 Trust I units and 18,400,000 Whiting USA Trust II (“Trust II”) units, and is amortized to income based on the units-of-production method.
Revenue Recognition	Revenue Recognition—Oil and gas revenues are recognized when production volumes are sold to a purchaser at a fixed or determinable price, delivery has occurred and title has transferred, persuasive evidence of a sales arrangement exists and collectability of the revenue is probable.  Revenues from the production of gas properties in which the Company has an interest with other producers are recognized on the basis of the Company’s net working interest (entitlement method).  Net deliveries in excess of entitled amounts are recorded as liabilities, while net under deliveries are reflected as receivables.  The Company’s aggregate imbalance positions  as of December 31, 2014 and 2013 were not significant.
	Taxes collected and remitted to governmental agencies on behalf of customers are not included in revenues or costs and expenses.
General and Administrative Expenses	General and Administrative Expenses—General and administrative expenses are reported net of reimbursements of overhead costs that are allocated to working interest owners which participate in oil and gas properties operated by Whiting.
Acquisition Cost	Acquisition Costs—Acquisition related expenses, which consist of external costs directly related to the Company’s acquisitions, such as advisory, legal, accounting, valuation and other professional fees, are expensed as incurred.
Maintenance and Repairs	Maintenance and Repairs—Maintenance and repair costs which do not extend the useful lives of property and equipment are charged to expense as incurred.  Major replacements, renewals and betterments are capitalized.
Income Taxes	Income Taxes—Income taxes are recognized based on earnings reported for tax return purposes in addition to a provision for deferred income taxes.  Deferred income taxes are accounted for using the liability method.  Under this method, deferred tax assets and liabilities are determined by applying the enacted statutory tax rates in effect at the end of a reporting period to the cumulative temporary differences between the tax bases of assets and liabilities and their reported amounts in the Company’s financial statements.  The effect on deferred taxes for a change in tax rates is recognized in income in the period that includes the enactment date.  A valuation allowance for deferred tax assets is established when it is more likely than not that some portion of the benefit from deferred tax assets will not be realized.  The Company’s uncertain tax positions must meet a more-likely-than-not realization threshold to be recognized, and any potential accrued interest and penalties related to unrecognized tax benefits are recognized within income tax expense.
Earnings Per Share	Earnings Per Share—Basic earnings per common share is calculated by dividing net income available to common shareholders by the weighted average number of common shares outstanding during each period.  Diluted earnings per common share is calculated by dividing adjusted net income available to common shareholders by the weighted average number of diluted common shares outstanding, which includes the effect of potentially dilutive securities.  Potentially dilutive securities for the diluted earnings per share calculations consist of unvested restricted stock awards and outstanding stock options using the treasury method, as well as convertible perpetual preferred stock using the if-converted method.  In the computation of diluted earnings per share, excess tax benefits that would be created upon the assumed vesting of unvested restricted shares or the assumed exercise of stock options (i.e. hypothetical excess tax benefits) are included in the assumed proceeds component of the treasury share method to the extent that such excess tax benefits are more likely than not to be realized.  When a loss from continuing operations exists, all potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted earnings per share.
Industry Segment and Geographic Information	Industry Segment and Geographic Information—The Company has evaluated how it is organized and managed and has identified only one operating segment, which is the exploration and production of crude oil, NGLs and natural gas.  The Company considers its gathering, processing and marketing functions as ancillary to its oil and gas producing activities.  All of the Company’s operations and assets are located in the United States, and substantially all of its revenues are attributable to United States customers.
Concentration of Credit Risk	Concentration of Credit Risk—Whiting is exposed to credit risk in the event of nonpayment by counterparties, a significant portion of which are concentrated in energy related industries.  The creditworthiness of customers and other counterparties is subject to continuing review.  The following table presents the percentages by purchaser that accounted for 10% or more of the Company’s total oil, NGL and natural gas sales for the years ended December 31, 2014, 2013 and 2012:
		2014	2013	2012
	Plains Marketing LP	17%	21%	20%
	Shell Trading US	10%	14%	14%
	Bridger Trading LLC	10%	8%	11%
	Eighty Eight Oil Company	6%	11%	11%
	Commodity derivative contracts held by the Company are with seven counterparties, all of which are participants in Whiting’s credit facility as well, and all of which have investment-grade ratings from Moody’s and Standard & Poor.  As of December 31, 2014, outstanding derivative contracts with Wells Fargo Bank, N.A., JP Morgan Chase Bank, N.A. and Canadian Imperial Bank of Commerce represented 34%,  28% and 13%, respectively, of total crude oil volumes hedged.
Reclassifications	Reclassifications—Certain prior period balances in the consolidated balance sheets have been reclassified to conform to the current year presentation.  Such reclassifications had no impact on net income, cash flows or shareholders’ equity previously reported.
Adopted and Recently Issued Accounting Pronouncements	Adopted and Recently Issued Accounting Pronouncements—In February 2013, the FASB issued Accounting Standards Update No. 2013-04, Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date (“ASU 2013-04”).  The objective of ASU 2013-04 is to provide guidance for the recognition, measurement and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation within the scope of this guidance is fixed at the reporting date.  ASU 2013-04 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013.  The Company adopted ASU 2013-04 effective January 1, 2014, which did not have an impact on the Company’s consolidated financial statements.
	In July 2013, the FASB issued Accounting Standards Update No. 2013-11, Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists (“ASU 2013-11”).  The objective of ASU 2013-11 is to provide guidance on financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists.  ASU 2013-11 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013.  The Company adopted ASU 2013-11 effective January 1, 2014, which did not have an impact on the Company’s consolidated financial statements, other than insignificant balance sheet reclassifications.
	In May 2014, the FASB issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (“ASU 2014‑09”).  The objective of ASU 2014-09 is to clarify the principles for recognizing revenue and to develop a common revenue standard for U.S. GAAP and International Financial Reporting Standards.  ASU 2014‑09 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016.  The Company is currently evaluating the impact of adopting ASU 2014‑09, but the standard is not expected to have a significant effect on its consolidated financial statements.
	In August 2014, the FASB issued Accounting Standards Update No. 2014-15, Presentation of Financial Statements – Going Concern (“ASU 2014-15”).  The objective of ASU 2014-15 is to provide guidance on management’s responsibility to evaluate whether there is substantial doubt about a company’s ability to continue as a going concern and to provide related footnote disclosures.  ASU 2014-15 is effective for fiscal years ending after December 15, 2016, and annual and interim periods thereafter.  This standard is not expected to have an impact on the Company’s consolidated financial statements.

FAIR_VALUE_MEASUREMENTS_Policy

FAIR VALUE MEASUREMENTS (Policy)	12 Months Ended
	Dec. 31, 2014
FAIR VALUE MEASUREMENTS [Abstract]
Fair Value of Financial Instruments	Cash and cash equivalents, accounts receivable and payable are carried at cost, which approximates their fair value because of the short-term maturity of these instruments.  The Company’s credit agreement has a recorded value that approximates its fair value since its variable interest rate is tied to current market rates.  The Company’s Senior Notes (including the Kodiak Notes) and Senior Subordinated Notes are recorded at cost, and the fair values of these instruments are included in the Long-Term Debt footnote.  The Company’s derivative financial instruments are recorded at fair value and include a measure of the Company’s own nonperformance risk or that of its counterparties as appropriate.

SUMMARY_OF_SIGNIFICANT_ACCOUNT2

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)	12 Months Ended
	Dec. 31, 2014
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES [Abstract]
Percentages of total oil and gas sales to significant purchasers
		2014	2013	2012
	Plains Marketing LP	17%	21%	20%
	Shell Trading US	10%	14%	14%
	Bridger Trading LLC	10%	8%	11%
	Eighty Eight Oil Company	6%	11%	11%

OIL_AND_GAS_PROPERTIES_Tables

OIL AND GAS PROPERTIES (Tables)	12 Months Ended
	Dec. 31, 2014
OIL AND GAS PROPERTIES [Abstract]
Net capitalized costs related to oil and gas producing activities
		December 31,
		2014		2013
	Proved leasehold costs	$	3,637,026	$	1,633,495
	Unproved leasehold costs		1,232,040		372,298
	Costs of completed wells and facilities		9,319,808		7,563,350
	Wells and facilities in progress		760,828		496,007
	Total oil and gas properties, successful efforts method		14,949,702		10,065,150
	Accumulated depletion		-3,003,270		-2,645,841
	Oil and gas properties, net	$	11,946,432	$	7,419,309

ACQUISITIONS_AND_DIVESTITURES_

ACQUISITIONS AND DIVESTITURES (Tables)	12 Months Ended
	Dec. 31, 2014
Williston Basin [Member]
Significant Acquisitions and Disposals [Line Items]
Assets acquired and liabilities assumed
	Purchase price		$	255,537
	Allocation of purchase price:
	Oil and gas properties, successful efforts method:
	Proved properties		$	229,002
	Unproved properties			27,335
	Oil in tank inventory			522
	Accounts receivable			578
	Asset retirement obligations			-1,900
	Total		$	255,537
Kodiak [Member]
Significant Acquisitions and Disposals [Line Items]
Assets acquired and liabilities assumed
	Consideration:
	Fair value of Whiting’s common stock issued (1)		$	1,771,094
	Fair value of Kodiak restricted stock units assumed by Whiting (2)			9,596
	Fair value of Kodiak options assumed by Whiting			7,523
	Total consideration		$	1,788,213
	Fair value of liabilities assumed:
	Accounts payable trade		$	18,390
	Accrued capital expenditures			104,509
	Revenues and royalties payable			57,423
	Accrued liabilities and other			45,695
	Taxes payable			12,676
	Accrued interest			18,070
	Current deferred tax liability			30,279
	Long-term debt			2,500,875
	Asset retirement obligations			8,646
	Other long-term liabilities			15,735
	Amount attributable to liabilities assumed		$	2,812,298
	Fair value of assets acquired:
	Cash and cash equivalents		$	18,879
	Accounts receivable trade, net			219,654
	Derivative assets			85,718
	Prepaid expenses and other			8,624
	Oil and gas properties, successful efforts method:
	Proved properties			2,266,607
	Unproved properties			1,000,396
	Other property and equipment			11,347
	Long-term deferred tax asset			107,497
	Other long-term assets			6,113
	Amount attributable to assets acquired		$	3,724,835
	Goodwill		$	875,676
	_____________________
		-1		47,546,139 shares of Whiting common stock at $37.25 per share (closing price as of December 5, 2014), based on Kodiak’s 268,622,497 common shares outstanding at closing.
		-2		257,601 shares of Whiting common stock issued at $37.25 per share (closing price as of December 5, 2014), based on Kodiak’s 1,455,409 restricted stock units held by employees as of December 8, 2014.
Unaudited pro forma operating results
			December 31,
			2014		2013
			(in thousands, except per share data)
	Total revenues		$	4,141,046	$	3,774,137
	Net income available to common shareholders		$	362,376	$	576,450
	Earnings per common share:
	Basic		$	2.18	$	3.48
	Diluted		$	2.17	$	3.46

LONGTERM_DEBT_Tables

LONG-TERM DEBT (Tables)	12 Months Ended
	Dec. 31, 2014
LONG-TERM DEBT [Abstract]
Schedule of long-term debt
			December 31,
			2014			2013
	Credit agreement		$	1,400,000		$	-
	6.5% Senior Subordinated Notes due 2018			350,000			350,000
	5% Senior Notes due 2019			1,100,000			1,100,000
	8.125% Senior Notes due 2019, including unamortized debt premium of $23,742			823,742			-
	5.75% Senior Notes due 2021, including unamortized debt premium of $3,180 and $3,834, respectively			1,203,180			1,203,834
	5.5% Senior Notes due 2021, including unamortized debt premium of $867			350,867			-
	5.5% Senior Notes due 2022, including unamortized debt premium of $993			400,993			-
	Total debt		$	5,628,782		$	2,653,834
Schedule of five succeeding fiscal years of scheduled maturities for the Company's long-term debt			2015			2016		2017		2018		2019
	Long-term debt (1)		$	-		$	-	$	-	$	350,000	$	3,300,000
	_____________________
		-1		Refer to “Kodiak Senior Notes Repurchase Offer” below for more information.
Summary of margin rates and commitment fees
			Applicable		Applicable
			Margin for Base		Margin for		Commitment
	Ratio of Outstanding Borrowings to Borrowing Base		Rate Loans		Eurodollar Loans		Fee
	Less than 0.25 to 1.0		0.50%		1.50%		0.38%
	Greater than or equal to 0.25 to 1.0 but less than 0.50 to 1.0		0.75%		1.75%		0.38%
	Greater than or equal to 0.50 to 1.0 but less than 0.75 to 1.0		1.00%		2.00%		0.50%
	Greater than or equal to 0.75 to 1.0 but less than 0.90 to 1.0		1.25%		2.25%		0.50%
	Greater than or equal to 0.90 to 1.0		1.50%		2.50%		0.50%

ASSET_RETIREMENT_OBLIGATIONS_T

ASSET RETIREMENT OBLIGATIONS (Tables)	12 Months Ended
	Dec. 31, 2014
ASSET RETIREMENT OBLIGATIONS [Abstract]
Schedule of reconciliation of the Company's asset retirement obligations
			December 31,
			2014		2013
	Asset retirement obligation at January 1		$	126,148	$	97,818
	Additional liability incurred			29,186		17,535
	Revisions in estimated cash flows (1)			25,909		12,225
	Accretion expense			13,548		10,608
	Obligations on sold properties			-7,237		-3,630
	Liabilities settled			-7,623		-8,408
	Asset retirement obligation at December 31		$	179,931	$	126,148
	_____________________
		-1		Revisions in estimated cash flows during the year ended December 31, 2014 are primarily attributable to increased estimates of future costs for oilfield goods and services required to plug and abandon wells in certain fields in the Rocky Mountains and Permian Basin regions.  Revisions in estimated cash flows during the year ended December 31, 2013 were primarily attributable to increased estimates of futures costs for oilfield goods and services required to plug and abandon wells in certain fields in the Rocky Mountains region.

DERIVATIVE_FINANCIAL_INSTRUMEN1

DERIVATIVE FINANCIAL INSTRUMENTS (Tables)	12 Months Ended
	Dec. 31, 2014
Derivative Financial Instruments [Line Items]
Schedule of effects of commodity derivative instruments
					Loss Reclassified from AOCI into
					Income (Effective Portion)
	ASC 815 Cash Flow				Year Ended December 31,
	Hedging Relationships (1)		Income Statement Classification		2014			2013
	Commodity contracts		Gain (loss) on hedging activities		$	-		$	-1,958
	_____________________
		-1		Effective April 1, 2009, the Company de-designated all of its commodity derivative contracts that had been previously designated as cash flow hedges and elected to discontinue hedge accounting prospectively.  As a result, such mark-to-market values at March 31, 2009 were frozen in AOCI as of the de-designation date and were reclassified into earnings as the original hedged transactions affected income.  As of December 31, 2013, all amounts previously in AOCI had been reclassified into earnings.
					(Gain) Loss Recognized in Income
	Not Designated as				Year Ended December 31,
	ASC 815 Hedges		Income Statement Classification		2014			2013
	Commodity contracts		Commodity derivative (gain) loss, net		$	-136,995		$	20,503
	Embedded commodity contracts		Commodity derivative (gain) loss, net			36,416			-12,701
	Total				$	-100,579		$	7,802
Location and fair value of derivative instruments
					December 31, 2014 (1)
										Net
					Gross					Recognized
					Recognized			Gross		Fair Value
	Not Designated as				Assets/			Amounts		Assets/
	ASC 815 Hedges		Balance Sheet Classification		Liabilities			Offset		Liabilities
	Derivative assets:
	Commodity contracts		Derivative assets		$	154,329		$	-18,752	$	135,577
	Commodity contracts		Other long-term assets			45,459			-		45,459
	Total derivative assets				$	199,788		$	-18,752	$	181,036
	Derivative liabilities:
	Commodity contracts				$	18,752		$	-18,752	$	-
	Total derivative liabilities				$	18,752		$	-18,752	$	-
					December 31, 2013 (1)
										Net
					Gross					Recognized
					Recognized			Gross		Fair Value
	Not Designated as				Assets/			Amounts		Assets/
	ASC 815 Hedges		Balance Sheet Classification		Liabilities			Offset		Liabilities
	Derivative assets:
	Commodity contracts		Derivative assets		$	23,752		$	-22,478	$	1,274
	Embedded commodity contracts		Other long-term assets			36,416			-		36,416
	Total derivative assets				$	60,168		$	-22,478	$	37,690
	Derivative liabilities:
	Commodity contracts		Accrued liabilities and other		$	25,960		$	-22,478	$	3,482
	Total derivative liabilities				$	25,960		$	-22,478	$	3,482
	_____________________
		-1		Because counterparties to the Company’s financial derivative contracts are lenders under Whiting Oil and Gas’ credit agreement, which eliminates its need to post or receive collateral associated with its derivative positions, columns for cash collateral pledged or received have not been presented in the tables above.
Whiting Petroleum Corporation [Member]
Derivative Financial Instruments [Line Items]
Derivative instruments
					Whiting Petroleum Corporation
	Derivative				Contracted Crude		Weighted Average NYMEX Price
	Instrument		Period		Oil Volumes (Bbl)		Collar Ranges for Crude Oil (per Bbl)
	Three-way collars (1)		Jan - Dec 2015		3,600,000		$50.83 - $62.50 - $83.81
			Jan - Dec 2016		6,600,000		$43.18 - $53.18 - $76.26
	Collars		Jan - Dec 2015		1,309,500		$52.47 - $59.26
			Jan - Dec 2016		3,000,000		$51.00 - $63.48
			Jan - Dec 2017		3,000,000		$53.00 - $70.44
	Swaps		Jan - Dec 2015		3,556,560		$86.05
			Total		21,066,060
	_____________________
		-1		A three-way collar is a combination of options: a sold call, a purchased put and a sold put.  The sold call establishes a maximum price (ceiling) Whiting will receive for the volumes under contract.  The purchased put establishes a minimum price (floor), unless the market price falls below the sold put (sub-floor), at which point the minimum price would be NYMEX plus the difference between the purchased put and the sold put strike price.

FAIR_VALUE_MEASUREMENTS_Tables

FAIR VALUE MEASUREMENTS (Tables)	12 Months Ended
	Dec. 31, 2014
FAIR VALUE MEASUREMENTS [Abstract]
Fair value assets and liabilities measured on a recurring basis
											Total Fair Value
			Level 1			Level 2		Level 3			31-Dec-14
	Financial Assets
	Commodity derivatives – current		$	-		$	127,506	$	8,071		$	135,577
	Commodity derivatives – non-current			-			-		45,459			45,459
	Total financial assets		$	-		$	127,506	$	53,530		$	181,036
											Total Fair Value
			Level 1			Level 2		Level 3			31-Dec-13
	Financial Assets
	Commodity derivatives – current		$	-		$	1,274	$	-		$	1,274
	Embedded commodity derivatives – non-current			-			-		36,416			36,416
	Total financial assets		$	-		$	1,274	$	36,416		$	37,690
	Financial Liabilities
	Commodity derivatives – current		$	-		$	3,482	$	-		$	3,482
	Total financial liabilities		$	-		$	3,482	$	-		$	3,482
Reconciliation of changes in the fair value of financial assets (liabilities) designated as Level 3 in the valuation hierarchy
			Year Ended
			December 31,
			2014			2013
	Fair value asset, beginning of period		$	36,416		$	23,715
	Unrealized gains (losses) on commodity derivative contracts included in earnings (1)			17,114			12,701
	Transfers into (out of) Level 3			-			-
	Fair value asset, end of period		$	53,530		$	36,416
	_____________________
		-1		Included in commodity derivative (gain) loss, net in the consolidated statements of income.
Significant unobservable inputs used in the fair value measurement
			Fair Value at
			31-Dec-14		Valuation		Unobservable	Amount
			(in thousands)		Technique		Input	(per Bbl)
	Commodity derivative contracts		$53,530		Income approach		Market differential for crude oil	$5.74
Non-financial assets and liabilities measured at fair value on a nonrecurring basis
																Loss (Before
			Net Carrying													Tax) Year
			Value as of													Ended
			December 31,			Fair Value Measurements Using										December 31,
			2014			Level 1			Level 2					Level 3		2014
	Proved property impairments (1)		$	179,155		$	-		$	-				$	179,155	$	629,450
	_____________________
		-1		During the year ended December 31, 2014, proved oil and gas properties with a carrying amount of $763 million were written down to their fair value of $176 million, resulting in a non-cash impairment charge of $587 million.  The impairment primarily consisted of non-core oil and gas properties, that are not currently being developed, in Colorado, Louisiana, North Dakota and Utah and related to the decrease in the forward price curve for crude oil and natural gas on December 31, 2014 and the associated decline in oil and gas reserves in those areas.  Also during the year ended December 31, 2014, proved CO2 properties at the Bravo Dome field in New Mexico with a carrying amount of $45 million were written down to their fair value of $3 million, resulting in a non-cash impairment charge of $42 million.
													Loss (Before
			Net Carrying										Tax) Year
			Value as of										Ended
			December 31,			Fair Value Measurements Using							December 31,
			2013			Level 1		Level 2			Level 3		2013
	Proved property impairments (1)		$	106,114		$	-	$	-		$	106,114	$	267,109
	_____________________
		-1		During the year ended December 31, 2013, proved oil and gas properties with a carrying amount of $373 million were written down to their fair value of $106 million, resulting in a non-cash impairment charge of $267 million.  The impairment consisted of (i) a $221 million write-down in the Rocky Mountains region and Michigan related to the decrease in the forward price curve for natural gas at December 31, 2013 and the associated decline in gas reserves in those areas and (ii) a $46 million write-down in the Rocky Mountains region related to well performance and associated changes in reserves during the fourth quarter of 2013.

DEFERRED_COMPENSATION_Tables

DEFERRED COMPENSATION (Tables)	12 Months Ended
	Dec. 31, 2014
DEFERRED COMPENSATION [Abstract]
Schedule of changes in the plan's estimated long-term liability
		Year Ended December 31,
			2014		2013
	Long-term Production Participation Plan liability at January 1	$	87,503	$	94,483
	Change in liability for accretion, vesting, changes in estimates and new Plan year activity prior to Plan termination		-		66,284
	Change in liability for vesting and PUDs assigned upon Plan termination		25,888		-
	Amount reflected as a current liability		-113,391		-73,264
	Long-term Production Participation Plan liability at December 31	$	-	$	87,503

SHAREHOLDERS_EQUITY_AND_NONCON1

SHAREHOLDERS' EQUITY AND NONCONTROLLING INTEREST (Tables)	12 Months Ended
	Dec. 31, 2014
Business Acquisition [Line Items]
Assumption for valuing market based restricted shares
		2014		2013		2012
	Number of simulations	65,000		65,000		65,000
	Expected volatility	42.30%		43.10%		51.90%
	Risk-free interest rate	0.86%		0.41%		0.35%
	Dividend yield	-		-		-
Summary of nonvested restricted stock
					Weighted Average
		Number			Grant Date
		of Shares			Fair Value
	Restricted stock awards nonvested, January 1, 2012		724,395		$	29.88
	Granted		592,400			34.45
	Vested		-357,170			17.91
	Forfeited		-8,599			51.72
	Restricted stock awards nonvested, December 31, 2012		951,026			37.02
	Granted		940,792			27.59
	Vested		-347,824			35.32
	Forfeited		-99,684			30.95
	Restricted stock awards nonvested, December 31, 2013		1,444,310			31.71
	Granted		907,856			32.41
	Assumed in Kodiak Acquisition (1)		304,926			37.25
	Vested		-814,439			34.05
	Forfeited		-385,785			34.86
	Restricted stock awards nonvested, December 31, 2014		1,456,868		$	31.16
Assumptions used to estimate the grant date fair value of stock options awarded
		2012
	Risk-free interest rate	1.19%
	Expected volatility	61.40%
	Expected term	6.0 yrs.
	Dividend yield	-
Summary of stock options outstanding
									Weighted
									Average
				Weighted			Aggregate		Remaining
				Average			Intrinsic		Contractual
		Number of		Exercise Price			Value		Term
		Options		per Share			(in thousands)		(in years)
	Options outstanding at January 1, 2012	377,336		$	26.09
	Granted	45,359			51.22
	Exercised	-			-		$	-
	Forfeited or expired	-			-
	Options outstanding at December 31, 2012	422,695			28.79
	Granted	-			-
	Exercised	-			-		$	-
	Forfeited or expired	-1,855			60.28
	Options outstanding at December 31, 2013	420,840			28.65
	Granted	-			-
	Assumed in Kodiak Acquisition	673,235			44.48
	Exercised	-117,123			15.21		$	6,203,361
	Forfeited or expired	-8,559			50.51
	Options outstanding at December 31, 2014	968,393		$	41.09		$	5,216,952	4.8
	Options vested and expected to vest at December 31, 2014	905,107		$	40.78		$	4,984,431	4.8
	Options exercisable at December 31, 2014	831,220		$	38.45		$	5,216,952	4.2
Schedule of noncontrolling interest
		Year Ended
		December 31,
		2014			2013
	Balance at January 1	$	8,132		$	8,184
	Net loss		-62			-52
	Balance at December 31	$	8,070		$	8,132
Kodiak [Member]
Business Acquisition [Line Items]
Assumptions used to estimate the grant date fair value of stock options awarded
		2014
	Risk-free interest rate	0.08% - 1.90%
	Expected volatility	40.3% - 49.7%
	Expected term	2.0 yrs. - 6.1 yrs.
	Dividend yield	-

INCOME_TAXES_Tables

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2014
INCOME TAXES [Abstract]
Schedule of income tax expense
		Year Ended December 31,
		2014		2013		2012
	Current income tax expense (refund):
	Federal	$	-2,758	$	7,060	$	-
	State		5,383		-6,074		-669
	Total current income tax expense (refund)		2,625		986		-669
	Deferred income tax expense:
	Federal		65,522		196,787		233,468
	State		11,023		8,095		15,113
	Total deferred income tax expense		76,545		204,882		248,581
	Total	$	79,170	$	205,868	$	247,912
Reconciliation of statutory income tax expense to income tax expense
		Year Ended December 31,
		2014		2013		2012
	U.S. statutory income tax expense	$	50,371	$	200,155	$	231,704
	State income taxes, net of federal benefit		12,705		13,962		14,444
	State income tax credits		-		-10,525		-
	Statutory depletion		-618		-796		-620
	Enacted changes in state tax laws		3,700		-1,416		-
	Market-based equity awards		2,805		-		-
	Permanent items		3,504		2,122		1,524
	Transaction costs		6,936		-		-
	Other		-233		2,366		860
	Total	$	79,170	$	205,868	$	247,912
Components of deferred income tax assets and liabilities
		Year Ended December 31,
		2014		2013
	Deferred income tax assets:
	Net operating loss carryforward	$	588,330	$	438,922
	Production Participation Plan liability		26,942		32,245
	Tax sharing liability		-		9,439
	Asset retirement obligations		13,791		23,642
	Underwriter fees		14,065		10,974
	Restricted stock compensation		15,527		13,384
	Premium on Senior Notes		7,979		-
	EOR credit carryforwards		7,946		7,946
	Alternative minimum tax credit carryforwards		15,694		18,452
	Transaction costs		7,957		-
	Other		9,493		3,234
	Total deferred income tax assets		707,724		558,238
	Less valuation allowance		-5,638		-1,230
	Net deferred income tax assets		702,086		557,008
	Deferred income tax liabilities:
	Oil and gas properties		1,785,926		1,675,916
	Trust distributions		129,437		149,332
	Derivative instruments		64,898		10,438
	Total deferred income tax liabilities		1,980,261		1,835,686
	Total net deferred income tax liabilities	$	1,278,175	$	1,278,678
Net deferred income tax liabilities
		Year Ended December 31,
		2014		2013
	Assets:
	Current deferred income taxes	$	-	$	-
	Liabilities:
	Current deferred income taxes		47,545		648
	Non-current deferred income taxes		1,230,630		1,278,030
	Net deferred income tax liabilities	$	1,278,175	$	1,278,678
Liability for unrecognized tax benefits
		Year Ended December 31,
		2014		2013		2012
	Beginning balance at January 1	$	170	$	170	$	299
	Decrease related to tax position taken in a prior period		-		-		-129
	Ending balance at December 31	$	170	$	170	$	170

EARNINGS_PER_SHARE_Tables

EARNINGS PER SHARE (Tables)	12 Months Ended
	Dec. 31, 2014
EARNINGS PER SHARE [Abstract]
Reconciliations between basic and diluted earnings per share
			Year Ended
			December 31,
			2014		2013		2012
	Basic Earnings Per Share
	Numerator:
	Net income available to shareholders		$	64,807	$	366,055	$	414,189
	Preferred stock dividends (1)			-		-494		-1,077
	Net income available to common shareholders, basic		$	64,807	$	365,561	$	413,112
	Denominator:
	Weighted average shares outstanding, basic			122,138		118,260		117,601
	Diluted Earnings Per Share
	Numerator:
	Net income available to common shareholders, basic		$	64,807	$	365,561	$	413,112
	Preferred stock dividends			-		538		1,077
	Adjusted net income available to common shareholders, diluted		$	64,807	$	366,099	$	414,189
	Denominator:
	Weighted average shares outstanding, basic			122,138		118,260		117,601
	Restricted stock and stock options			381		957		633
	Convertible perpetual preferred stock			-		371		794
	Weighted average shares outstanding, diluted			122,519		119,588		119,028
	Earnings per common share, basic		$	0.53	$	3.09	$	3.51
	Earnings per common share, diluted		$	0.53	$	3.06	$	3.48
	_____________________
		-1		For the year ended December 31, 2013, amount includes a decrease of $0.04 million in preferred stock dividends for preferred stock dividends accumulated.  There were no accumulated dividend adjustments for the years ended December 31, 2014 or 2012.

RELATED_PARTY_TRANSACTIONS_Tab

RELATED PARTY TRANSACTIONS (Tables)	12 Months Ended
	Dec. 31, 2014
RELATED PARTY TRANSACTIONS [Abstract]
Summary of related party receivable and payable balances
			December 31,
			2014		2013
	Assets
	Unit distributions due from Trust I (1)		$	652	$	1,093
	Liabilities
	Unit distributions payable to Trust I (2)		$	4,133	$	6,932
	_____________________
		-1		This amount represents Whiting’s 15.8% interest in the net proceeds due from Trust I and is included within accounts receivable trade, net in the Company’s consolidated balance sheets.
		-2		This amount represents net proceeds from Trust I’s underlying properties that the Company has received between the last Trust I distribution date and December 31, 2014 and 2013, respectively, but which the Company has not yet distributed to Trust I as of December 31, 2014 and 2013, respectively.  Due to ongoing processing of Trust I revenues and expenses after December 31, 2014 and 2013, the amount of Whiting’s next scheduled distribution to Trust I, and the related distribution by Trust I to its unitholders, will differ from this amount.  These amounts are included within accounts payable trade in the Company’s consolidated balance sheet.

COMMITMENTS_AND_CONTINGENCIES_

COMMITMENTS AND CONTINGENCIES (Tables)	12 Months Ended
	Dec. 31, 2014
COMMITMENTS AND CONTINGENCIES [Abstract]
Minimum future payments under non-cancelable operating leases and unconditional purchase obligations
		Payments due by period
		2015		2016		2017		2018		2019		Thereafter		Total
	Non-cancelable leases	$	7,692	$	7,547	$	6,610	$	6,693	$	5,844	$	216	$	34,602
	Drilling rig contracts		146,141		101,855		30,788		-		-		-		278,784
	Pipeline transportation agreements		5,948		9,722		9,559		9,559		9,559		50,091		94,438
	Total	$	159,781	$	119,124	$	46,957	$	16,252	$	15,403	$	50,307	$	407,824

OIL_AND_GAS_ACTIVITIES_Tables

OIL AND GAS ACTIVITIES (Tables)	12 Months Ended
	Dec. 31, 2014
OIL AND GAS ACTIVITIES [Abstract]
Schedule of cost Incurred in oil and gas producing activities
			Year Ended December 31,
			2014		2013		2012
	Development (1)		$	2,891,893	$	2,132,824	$	1,667,182
	Proved property acquisition (2)			2,278,855		232,572		19,785
	Unproved property acquisition (2)			1,035,439		174,103		119,175
	Exploration			216,587		363,234		436,084
	Total		$	6,422,774	$	2,902,733	$	2,242,226
	_____________________
		-1		During 2014, 2013 and 2012, non-cash additions to oil and gas properties of $45 million, $30 million and $36 million, respectively, which relate to estimated costs of the future plugging and abandonment of the Company’s oil and gas wells, are included in development costs in the table above.
		-2		During 2014, amounts include $2.3 billion of non-cash proved property additions and $1.0 billion of non-cash unproved property additions related to the Kodiak Acquisition.
Net capitalized costs related to the Companybs oil and gas producing activities
			Year Ended December 31,
			2014		2013
	Proved oil and gas properties		$	12,956,834	$	9,196,845
	Unproved oil and gas properties			1,992,868		868,305
	Accumulated depletion			-3,003,270		-2,645,841
	Oil and gas properties, net		$	11,946,432	$	7,419,309
Net changes in capitalized exploratory well costs
			Year Ended December 31,
			2014		2013		2012
	Beginning balance at January 1		$	85,378	$	108,861	$	90,519
	Additions to capitalized exploratory well costs pending the determination of proved reserves			145,336		281,951		384,223
	Reclassifications to wells, facilities and equipment based on the determination of proved reserves			-200,869		-291,962		-358,625
	Capitalized exploratory well costs charged to expense			-15,552		-13,472		-7,256
	Ending balance at December 31		$	14,293	$	85,378	$	108,861

DISCLOSURES_ABOUT_OIL_AND_GAS_1

DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (Tables)	12 Months Ended
	Dec. 31, 2014
DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES [Abstract]
Summary of changes in quantities of proved oil and gas reserve
		Oil		NGLs		Natural Gas	Total
		(MBbl)		(MBbl)		(MMcf)	(MBOE)
	Balance—January 1, 2012	260,144		37,609		284,975	345,249
	Extensions and discoveries	68,134		6,526		40,915	81,479
	Sales of minerals in place	-7,960		-320		-13,987	-10,611
	Production	-23,139		-2,766		-25,827	-30,209
	Revisions to previous estimates	4,106		-951		-61,812	-7,148
	Balance—December 31, 2012	301,285		40,098		224,264	378,760
	Extensions and discoveries	88,293		9,830		63,893	108,772
	Sales of minerals in place	-36,992		-4,777		-12,411	-43,838
	Purchases of minerals in place	14,543		1,311		7,751	17,146
	Production	-27,035		-2,821		-26,917	-34,342
	Revisions to previous estimates	7,327		1,228		20,934	12,044
	Balance—December 31, 2013	347,421		44,869		277,514	438,542
	Extensions and discoveries	146,122		12,947		94,452	174,811
	Sales of minerals in place	-1,642		-		-2,925	-2,130
	Purchases of minerals in place	169,586		-		156,140	195,609
	Production	-33,485		-3,283		-30,218	-41,804
	Revisions to previous estimates	15,627		151		-2,943	15,288
	Balance—December 31, 2014	643,629		54,684		492,020	780,316
	Proved developed reserves:
	31-Dec-11	180,975		22,109		211,297	238,300
	31-Dec-12	190,845		24,204		160,893	241,864
	31-Dec-13	198,204		23,721		183,129	252,446
	31-Dec-14	333,593		28,935		298,237	412,234
	Proved undeveloped reserves:
	31-Dec-11	79,169		15,500		73,678	106,949
	31-Dec-12	110,440		15,894		63,371	136,896
	31-Dec-13	149,217		21,148		94,385	186,096
	31-Dec-14	310,036		25,749		193,783	368,082
Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves
		December 31,
		2014			2013		2012
	Future cash flows	$	59,949,707		$	35,178,399	$	29,308,752
	Future production costs		-20,772,234			-12,973,292		-11,397,332
	Future development costs		-7,924,573			-5,355,383		-3,181,618
	Future income tax expense		-8,579,237			-3,954,401		-4,278,529
	Future net cash flows		22,673,663			12,895,323		10,451,273
	10% annual discount for estimated timing of cash flows		-11,830,243			-6,301,462		-5,044,240
	Standardized measure of discounted future net cash flows	$	10,843,420		$	6,593,861	$	5,407,033
Changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves
		December 31,
		2014			2013		2012
	Beginning of year	$	6,593,861		$	5,407,033	$	5,272,492
	Sale of oil and gas produced, net of production costs		-2,274,682			-2,010,925		-1,589,665
	Sales of minerals in place		-48,532			-1,064,195		-438,614
	Net changes in prices and production costs		81,522			902,916		-1,061,495
	Extensions, discoveries and improved recoveries		3,950,413			2,827,321		3,708,780
	Previously estimated development costs incurred during the period		1,149,926			832,096		526,982
	Changes in estimated future development costs		-3,382,849			-1,264,189		-1,498,592
	Purchases of minerals in place		4,420,417			445,669		-
	Revisions of previous quantity estimates		345,775			313,069		-295,432
	Net change in income taxes		-651,817			-335,637		255,328
	Accretion of discount		659,386			540,703		527,249
	End of year	$	10,843,420		$	6,593,861	$	5,407,033
Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves calculating average sales prices
		2014			2013		2012
	Oil (per Bbl)	$	84.69		$	90.8	$	87.15
	NGLs (per Bbl)	$	46.59		$	54.38	$	58.15
	Natural Gas (per Mcf)	$	5.88		$	4.3	$	3.21

QUARTERLY_FINANCIAL_DATA_Table

QUARTERLY FINANCIAL DATA (Tables)	12 Months Ended
	Dec. 31, 2014
QUARTERLY FINANCIAL DATA [Abstract]
Summary of the unaudited quarterly financial data
			Three Months Ended
			March 31,		June 30,		September 30,		December 31,
			2014		2014		2014		2014
	Oil, NGL and natural gas sales		$	721,250	$	825,760	$	805,054	$	672,553
	Operating profit (1)		$	311,169	$	370,033	$	326,215	$	177,722
	Net income (loss)		$	109,051	$	151,426	$	157,961	$	-353,693
	Basic earnings (loss) per share		$	0.92	$	1.27	$	1.33	$	-2.69
	Diluted earnings (loss) per share		$	0.91	$	1.26	$	1.32	$	-2.68
			Three Months Ended
			March 31,		June 30,		September 30,		December 31,
			2013		2013		2013		2013
	Oil, NGL and natural gas sales		$	605,114	$	651,868	$	706,543	$	703,024
	Operating profit (1)		$	252,806	$	269,528	$	316,764	$	280,311
	Net income (loss)		$	86,244	$	134,944	$	204,091	$	-59,276
	Basic earnings (loss) per share		$	0.73	$	1.14	$	1.72	$	-0.5
	Diluted earnings (loss) per share		$	0.72	$	1.14	$	1.71	$	-0.5
	_____________________
		-1		Oil, NGL and natural gas sales less lease operating expense, production taxes and depreciation, depletion and amortization.

SUMMARY_OF_SIGNIFICANT_ACCOUNT3

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Narrative I) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Summary Of Significant Accounting Policies [Line Items]
Oil and gas receivables collection period	2 months
Allowance for doubtful account	$9	$4
Interest cost capitalized	$4	$2	$3
Whiting USA Trust I [Member]
Summary Of Significant Accounting Policies [Line Items]
Company retained ownership (as a percent)	15.80%
Minimum [Member]
Summary Of Significant Accounting Policies [Line Items]
Estimated useful life	4 years
Maximum [Member]
Summary Of Significant Accounting Policies [Line Items]
Estimated useful life	30 years

SUMMARY_OF_SIGNIFICANT_ACCOUNT4

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Narrative II) (Details)	0 Months Ended	12 Months Ended
	Mar. 28, 2012	Dec. 31, 2014	Dec. 31, 2012
Concentration Risk [Line Items]
Number of operating segments		1
Whiting USA Trust I [Member]
Concentration Risk [Line Items]
Trust units sold to the public (in shares)		11,677,500
Whiting USA Trust II Units [Member]
Concentration Risk [Line Items]
Trust units sold to the public (in shares)	18,400,000	18,400,000	18,400,000
Commodity Price Risk [Member] | Derivative Contracts [Member]
Concentration Risk [Line Items]
Number of counterparties		7
Wells Fargo Bank [Member] | Commodity Price Risk [Member] | Derivative Contracts [Member]
Concentration Risk [Line Items]
Outstanding derivative contracts as percentage of crude oil volumes hedged		34.00%
JP Morgan Chase [Member] | Commodity Price Risk [Member] | Derivative Contracts [Member]
Concentration Risk [Line Items]
Outstanding derivative contracts as percentage of crude oil volumes hedged		28.00%
Canadian Imperial Bank Of Commerce [Member] | Commodity Price Risk [Member] | Derivative Contracts [Member]
Concentration Risk [Line Items]
Outstanding derivative contracts as percentage of crude oil volumes hedged		13.00%

SUMMARY_OF_SIGNIFICANT_ACCOUNT5

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Percentages of total oil and gas sales to significant purchases) (Details) (Credit Concentration Risk [Member], Oil And Gas Sales [Member])	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Plains Marketing LP [Member]
Concentration Risk [Line Items]
Sales as percentage of oil and gas revenue	17.00%	21.00%	20.00%
Shell Trading US [Member]
Concentration Risk [Line Items]
Sales as percentage of oil and gas revenue	10.00%	14.00%	14.00%
Bridger Trading LLC [Member]
Concentration Risk [Line Items]
Sales as percentage of oil and gas revenue	10.00%	8.00%	11.00%
Eighty Eight Oil Company [Member]
Concentration Risk [Line Items]
Sales as percentage of oil and gas revenue	6.00%	11.00%	11.00%

OIL_AND_GAS_PROPERTIES_Details

OIL AND GAS PROPERTIES (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
OIL AND GAS PROPERTIES [Abstract]
Proved leasehold costs	$3,637,026	$1,633,495
Unproved leasehold costs	1,232,040	372,298
Costs of completed wells and facilities	9,319,808	7,563,350
Wells and facilities in progress	760,828	496,007
Total oil and gas properties, successful efforts method	14,949,702	10,065,150
Accumulated depletion	-3,003,270	-2,645,841
Oil and gas properties, net	$11,946,432	$7,419,309

ACQUISITIONS_AND_DIVESTITURES_1

ACQUISITIONS AND DIVESTITURES (Narrative I) (Details) (USD $)	0 Months Ended	1 Months Ended
	Dec. 08, 2014	Dec. 31, 2014	Dec. 05, 2014
Business Acquisition [Line Items]
Goodwill deducted for income tax purposes		$0
Goodwill		875,676,000
Kodiak [Member]
Business Acquisition [Line Items]
Shares exchanged per each share owned	0.177
Total consideration	1,788,213,000
Aggregate purchase price	4,300,000,000
Outstanding debt	2,500,000,000
Cash acquired from acquisition	19,000,000
Gross acquisition area (in acres)	327,000
Net acquisition area (in acres)	178,000
Number of wells acquired	778
Goodwill	875,676,000
Revenue		46,000,000
Net income		$17,000,000
Kodiak [Member] | Wyoming And Colorado [Member]
Business Acquisition [Line Items]
Net acquisition area (in acres)	10,000
Common Stock [Member] | Kodiak [Member]
Business Acquisition [Line Items]
Awards Assumed in Kodiak Acquisition (in shares)	47,546,139
Closing price, per share			$37.25

ACQUISITIONS_AND_DIVESTITURES_2

ACQUISITIONS AND DIVESTITURES (Narrative II) (Details) (USD $)	0 Months Ended	12 Months Ended		0 Months Ended
	Mar. 28, 2012	Dec. 31, 2014	Dec. 31, 2012	Mar. 27, 2014	Oct. 31, 2013	Jul. 15, 2013	18-May-12	Sep. 20, 2013
	MBoe							acre
								item
Whiting USA Trust II Units [Member]
Acquisitions and divestitures [Line Items]
Proceeds from sale	$322,000,000
Number of units received in exchange of oil and gas properties contributed (in shares)	18,400,000	18,400,000	18,400,000
Price per unit of shares	$20
Deferred gain on sale	128,000,000
Percentage of units issued	100.00%
Entitled to receive percentage of net proceeds from sale of oil and gas production	90.00%
Termination of net profits interest, cumulative production from underlying properties (in MBOE)	11,790
Proved producing reserves conveyed (in MBOE)	10,610
Williston Basin [Member]
Acquisitions and divestitures [Line Items]
Gross acquisition area (in acres)								39,300
Net acquisition area (in acres)								17,300
Number of wells acquired								121
Purchase price for acquisition								261,000,000
Post-closing purchase price adjustments		6,000,000
Adjusted purchase price of tangible assets acquired and liabilities assumed		255,537,000
Big Tex prospect properties [Member]
Acquisitions and divestitures [Line Items]
Gross acquisition area (in acres)				49,900	45,000
Net acquisition area (in acres)				41,000	32,200
Proceeds from sale				76,000,000	151,000,000
Pre tax gain on Divestiture				12,000,000	11,000,000
Big Tex prospect properties [Member] | Pecos County, TX [Member]
Acquisitions and divestitures [Line Items]
Net acquisition area (in acres)					30,800
Big Tex prospect properties [Member] | Reeves County, TX [Member]
Acquisitions and divestitures [Line Items]
Net acquisition area (in acres)					1,400
Postle Properties [Member]
Acquisitions and divestitures [Line Items]
Ownership interest sold (as a percent)						60.00%
Proceeds from sale						809,000,000
Pre tax gain on Divestiture						109,000,000
Belfield Gas Processing Plant [Member]
Acquisitions and divestitures [Line Items]
Ownership interest sold (as a percent)							50.00%
Proceeds from sale							$66,000,000

ACQUISITIONS_AND_DIVESTITURES_3

ACQUISITIONS AND DIVESTITURES (Preliminary Consideration Transferred) (Details) (USD $)	12 Months Ended	0 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 08, 2014		Dec. 31, 2013	Dec. 05, 2014
Business Acquisition [Line Items]
Proved properties	$12,956,834			$9,196,845
Unproved properties	1,232,040			372,298
Goodwill	875,676
Common stock, shares issued	168,346,020			120,101,555
Restricted Stock Units (RSUs) [Member]
Business Acquisition [Line Items]
Fair value of Whitingbs common stock issued	9,596
Closing price, per share					$37.25
Stock Option [Member]
Business Acquisition [Line Items]
Fair value of Whitingbs common stock issued	7,523
Awards Assumed in Kodiak Acquisition (in shares)	673,235
Kodiak [Member] | Restricted Stock Units (RSUs) [Member]
Business Acquisition [Line Items]
Common stock, shares issued		1,455,409
Kodiak [Member]
Business Acquisition [Line Items]
Total consideration		1,788,213
Accounts payable trade		18,390
Accrued capital expenditures		104,509
Revenues and royalties payable		57,423
Accrued liabilities and other		45,695
Taxes payable		12,676
Accrued interest		18,070
Current deferred tax liability		30,279
Long-term debt		2,500,875
Asset retirement obligations		8,646
Other long-term liabilities		15,735
Amount attributable to liabilities assumed		2,812,298
Cash and cash equivalents		18,879
Accounts receivable trade, net		219,654
Derivative assets		85,718
Prepaid expenses and other		8,624
Proved properties		2,266,607
Unproved properties		1,000,396
Other property and equipment		11,347
Long-term deferred tax asset		107,497
Other long-term assets		6,113
Amount attributable to assets acquired		3,724,835
Goodwill		875,676
Common Stock [Member] | Restricted Stock Units (RSUs) [Member]
Business Acquisition [Line Items]
Awards Assumed in Kodiak Acquisition (in shares)	258,000	257,601
Common Stock [Member] | Kodiak [Member]
Business Acquisition [Line Items]
Common stock, shares issued		268,622,497
Common Stock [Member] | Kodiak [Member] | Restricted Stock Units (RSUs) [Member]
Business Acquisition [Line Items]
Fair value of Whitingbs common stock issued		9,596	[1]
Common Stock [Member] | Kodiak [Member] | Stock Option [Member]
Business Acquisition [Line Items]
Fair value of Whitingbs common stock issued		7,523
Common Stock [Member]
Business Acquisition [Line Items]
Fair value of Whitingbs common stock issued	1,771,094
Closing price, per share					$37.25
Common Stock [Member] | Common Stock [Member]
Business Acquisition [Line Items]
Fair value of Whitingbs common stock issued	48
Awards Assumed in Kodiak Acquisition (in shares)	47,546,000	47,546,139
Common Stock [Member] | Common Stock [Member] | Kodiak [Member]
Business Acquisition [Line Items]
Fair value of Whitingbs common stock issued		$1,771,094	[2]
[1]	257,601 shares of Whiting common stock issued at $37.25 per share (closing price as of December 5, 2014), based on Kodiakbs 1,455,409 restricted stock units held by employees as of December 8, 2014.
[2]	47,546,139 shares of Whiting common stock at $37.25 per share (closing price as of December 5, 2014), based on Kodiakbs 268,622,497 common shares outstanding at closing.

ACQUISITIONS_AND_DIVESTITURES_4

ACQUISITIONS AND DIVESTITURES (Purchase price allocation) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Significant Acquisitions and Disposals [Line Items]
Proved properties	$12,956,834	$9,196,845
Unproved properties	1,232,040	372,298
Williston Basin [Member]
Significant Acquisitions and Disposals [Line Items]
Proved properties	229,002
Unproved properties	27,335
Oil in tank inventory	522
Accounts receivable	578
Asset retirement obligations	-1,900
Total	$255,537

ACQUISITIONS_AND_DIVESTITURES_5

ACQUISITIONS AND DIVESTITURES (Unaudited Pro forma Operating Results) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Acquisition-related Costs [Member]
Business Acquisition [Line Items]
Acquisition-related costs	$86,000,000
Kodiak [Member]
Business Acquisition [Line Items]
Total revenues	4,141,046,000	3,774,137,000
Net income available to common shareholders	$362,376,000	$576,450,000
Net income (loss) per share: Basic	$2.18	$3.48
Net income (loss) per share: Diluted	$2.17	$3.46

LONGTERM_DEBT_Credit_agreement

LONG-TERM DEBT (Credit agreement) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014
LIBOR Rate, Scenario 1 [Member]
Debt disclosures [Line Items]
Basis points added to reference rate (as a percent)	2.00%
LIBOR rate, Scenario 2 [Member]
Debt disclosures [Line Items]
Basis points added to reference rate (as a percent)	2.50%
Whiting Oil and Gas Corporation [Member]
Debt disclosures [Line Items]
Maximum borrowing capacity of credit facility	4,500,000,000
Maximum aggregate commitments	3,500,000,000
Current borrowing capacity of credit facility	3,500,000,000
Whiting Oil and Gas Corporation [Member] | Amendment credit agreement [Member]
Debt disclosures [Line Items]
Borrowing capacity of credit facility, net of letter of credit	3,100,000,000
Outstanding borrowings under credit facility	1,400,000,000
Letters of credit borrowings outstanding	3,000,000
Portion of line of credit available for issuance of letters of credit	100,000,000
Amount of revolving credit agreement available for additional letters of credit under the agreement	97,000,000
Weighted average interest rate	1.90%
Restricted net assets	6,900,000,000
Retained earnings free from restrictions	24,000,000
EBITDAX ratio (percentage)	4
Minimum consolidated current assets to consolidated current liabilities ratio (percentage)	1
Whiting Oil and Gas Corporation [Member] | Amendment credit agreement [Member] | Base Rate [Member]
Debt disclosures [Line Items]
Basis points added to reference rate (as a percent)	0.50%
Variable interest rate basis	federal funds
Whiting Oil and Gas Corporation [Member] | Amendment credit agreement [Member] | LIBOR [Member]
Debt disclosures [Line Items]
Basis points added to reference rate (as a percent)	1.00%
Variable interest rate basis	LIBOR
Delayed Draw Facility [Member]
Debt disclosures [Line Items]
Commitment Fee (as a percent)	0.25%
Delayed Draw Facility [Member] | Base Rate, Scenario 1 [Member]
Debt disclosures [Line Items]
Basis points added to reference rate (as a percent)	1.00%
Delayed Draw Facility [Member] | Base Rate, Scenario 2 [Member]
Debt disclosures [Line Items]
Basis points added to reference rate (as a percent)	1.50%
Delayed Draw Facility [Member] | Whiting Oil and Gas Corporation [Member]
Debt disclosures [Line Items]
Maximum borrowing capacity of credit facility	1,000,000,000

LONGTERM_DEBT_Schedule_of_long

LONG-TERM DEBT (Schedule of long-term debt) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Sep. 30, 2010	Sep. 30, 2013	Sep. 26, 2013
In Thousands, unless otherwise specified
Debt Instrument [Line Items]
Long-term debt	$5,628,782	$2,653,834
Amendment credit agreement [Member]
Debt Instrument [Line Items]
Long-term debt	1,400,000
Senior Subordinated Notes [Member] | 6.5% Senior Subordinated Notes due 2018 [Member]
Debt Instrument [Line Items]
Long-term debt	350,000	350,000
Interest rate on debt instrument (as a percent)	6.50%	6.50%	6.50%
Senior Notes [Member] | 5% Senior Notes due 2019 [Member]
Debt Instrument [Line Items]
Long-term debt	1,100,000	1,100,000
Interest rate on debt instrument (as a percent)	5.00%	5.00%		5.00%
Senior Notes [Member] | 8.125% Kodiak Senior Notes due 2019 [Member]
Debt Instrument [Line Items]
Long-term debt	823,742
Interest rate on debt instrument (as a percent)	8.13%
Unamortized debt premium	23,742
Senior Notes [Member] | 5.75% Senior Notes due 2021 [Member]
Debt Instrument [Line Items]
Long-term debt	1,203,180	1,203,834
Interest rate on debt instrument (as a percent)	5.75%	5.75%		5.75%	5.75%
Unamortized debt premium	3,180	3,834
Senior Notes [Member] | 5.5% Kodiak Senior Notes due 2021 [Member]
Debt Instrument [Line Items]
Long-term debt	350,867
Interest rate on debt instrument (as a percent)	5.50%
Unamortized debt premium	867
Senior Notes [Member] | 5.5% Kodiak Senior Notes due 2022 [Member]
Debt Instrument [Line Items]
Long-term debt	400,993
Interest rate on debt instrument (as a percent)	5.50%
Unamortized debt premium	$993

LONGTERM_DEBT_Schedule_of_five

LONG-TERM DEBT (Schedule of five succeeding fiscal years of scheduled maturities for long-term debt) (Details) (USD $)	Dec. 31, 2014
In Thousands, unless otherwise specified
LONG-TERM DEBT [Abstract]
2018	$350,000	[1]
2019	$3,300,000	[1]
[1]	Refer to bKodiak Senior Notes Repurchase Offerb below for more information.

LONGTERM_DEBT_Summary_of_margi

LONG-TERM DEBT (Summary of margin rates and commitment fees) (Details) (Amendment credit agreement [Member], Whiting Oil and Gas Corporation [Member])	12 Months Ended
	Dec. 31, 2014
Base Rate [Member]
Debt Instrument [Line Items]
Variable interest rate basis	federal funds
Applicable Margin for Loans (as percent)	0.50%
Less than 0.25 to 1.0 [Member]
Debt Instrument [Line Items]
Variable interest rate basis	LIBOR
Alternate variable interest rate basis	base loan rate
Range, less than	0.25
Commitment Fee (as a percent)	0.38%
Less than 0.25 to 1.0 [Member] | Base Rate [Member]
Debt Instrument [Line Items]
Applicable Margin for Loans (as percent)	0.50%
Less than 0.25 to 1.0 [Member] | Eurodollar [Member]
Debt Instrument [Line Items]
Applicable Margin for Loans (as percent)	1.50%
Greater than or equal to 0.25 to 1.0 but less than 0.50 to 1.0 [Member]
Debt Instrument [Line Items]
Variable interest rate basis	LIBOR
Alternate variable interest rate basis	base loan rate
Range, greater than or equal to	0.25
Range, less than	0.5
Commitment Fee (as a percent)	0.38%
Greater than or equal to 0.25 to 1.0 but less than 0.50 to 1.0 [Member] | Base Rate [Member]
Debt Instrument [Line Items]
Applicable Margin for Loans (as percent)	0.75%
Greater than or equal to 0.25 to 1.0 but less than 0.50 to 1.0 [Member] | Eurodollar [Member]
Debt Instrument [Line Items]
Applicable Margin for Loans (as percent)	1.75%
Greater than or equal to 0.50 to 1.0 but less than 0.75 to 1.0 [Member]
Debt Instrument [Line Items]
Variable interest rate basis	LIBOR
Alternate variable interest rate basis	base loan rate
Range, greater than or equal to	0.5
Range, less than	0.75
Commitment Fee (as a percent)	0.50%
Greater than or equal to 0.50 to 1.0 but less than 0.75 to 1.0 [Member] | Base Rate [Member]
Debt Instrument [Line Items]
Applicable Margin for Loans (as percent)	1.00%
Greater than or equal to 0.50 to 1.0 but less than 0.75 to 1.0 [Member] | Eurodollar [Member]
Debt Instrument [Line Items]
Applicable Margin for Loans (as percent)	2.00%
Greater than or equal to 0.75 to 1.0 but less than 0.90 to 1.0 [Member]
Debt Instrument [Line Items]
Variable interest rate basis	LIBOR
Alternate variable interest rate basis	base loan rate
Range, greater than or equal to	0.75
Range, less than	0.9
Commitment Fee (as a percent)	0.50%
Greater than or equal to 0.75 to 1.0 but less than 0.90 to 1.0 [Member] | Base Rate [Member]
Debt Instrument [Line Items]
Applicable Margin for Loans (as percent)	1.25%
Greater than or equal to 0.75 to 1.0 but less than 0.90 to 1.0 [Member] | Eurodollar [Member]
Debt Instrument [Line Items]
Applicable Margin for Loans (as percent)	2.25%
Greater than or equal to 0.90 to 1.0 [Member]
Debt Instrument [Line Items]
Variable interest rate basis	LIBOR
Alternate variable interest rate basis	base loan rate
Range, greater than or equal to	0.9
Commitment Fee (as a percent)	0.50%
Greater than or equal to 0.90 to 1.0 [Member] | Base Rate [Member]
Debt Instrument [Line Items]
Applicable Margin for Loans (as percent)	1.50%
Greater than or equal to 0.90 to 1.0 [Member] | Eurodollar [Member]
Debt Instrument [Line Items]
Applicable Margin for Loans (as percent)	2.50%

LONGTERM_DEBT_Senior_notes_and

LONG-TERM DEBT (Senior notes and senior subordinated notes) (Details) (USD $)	12 Months Ended	1 Months Ended	0 Months Ended
	Dec. 31, 2013	Oct. 31, 2013	Jan. 07, 2015	Dec. 31, 2014	Sep. 30, 2010	Sep. 30, 2013	Sep. 26, 2013	Dec. 08, 2014
Debt disclosures [Line Items]
Payment for redemption of senior debt	($253,988,000)
Loss on early extinguishment of debt	-4,412,000
Long-term Debt	2,653,834,000			5,628,782,000
Senior Subordinated Notes [Member] | 6.5% Senior Subordinated Notes due 2018 [Member]
Debt disclosures [Line Items]
Interest rate on debt instrument (as a percent)	6.50%			6.50%	6.50%
Notes Issued					350,000,000
Estimated fair value of Notes	371,000,000			345,000,000
Long-term Debt	350,000,000			350,000,000
Senior Subordinated Notes [Member] | 7% Senior Subordinated Notes due 2014 [Member]
Debt disclosures [Line Items]
Interest rate on debt instrument (as a percent)	7.00%
Payment for redemption of senior debt		254,000,000
Senior subordinated notes redeemed, face amount		250,000,000
Percentage of redemption price		101.60%
Loss on early extinguishment of debt		4,000,000
Cash charge related to the redemption premium		4,000,000
Senior Notes [Member] | 5% Senior Notes due 2019 [Member]
Debt disclosures [Line Items]
Interest rate on debt instrument (as a percent)	5.00%			5.00%		5.00%
Notes Issued						1,100,000,000
Estimated fair value of Notes	1,100,000,000			1,000,000,000
Long-term Debt	1,100,000,000			1,100,000,000
Senior Notes [Member] | 5.75% Senior Notes due 2021 [Member]
Debt disclosures [Line Items]
Interest rate on debt instrument (as a percent)	5.75%			5.75%		5.75%	5.75%
Notes Issued						800,000,000	400,000,000
Estimated fair value of Notes	1,300,000,000			1,100,000,000
Premium as a percentage of par							101.00%
Unamortized debt premium	3,834,000			3,180,000
Long-term Debt	1,203,834,000			1,203,180,000
Senior Notes [Member] | 8.125% Kodiak Senior Notes due 2019 [Member]
Debt disclosures [Line Items]
Interest rate on debt instrument (as a percent)				8.13%
Notes Issued				800,000,000
Estimated fair value of Notes				812,000,000				824,000,000
Unamortized debt premium				23,742,000
Long-term Debt				823,742,000
Senior Notes [Member] | 5.5% Kodiak Senior Notes due 2021 [Member]
Debt disclosures [Line Items]
Interest rate on debt instrument (as a percent)				5.50%
Notes Issued				350,000,000
Estimated fair value of Notes				351,000,000				351,000,000
Unamortized debt premium				867,000
Long-term Debt				350,867,000
Senior Notes [Member] | 5.5% Kodiak Senior Notes due 2022 [Member]
Debt disclosures [Line Items]
Interest rate on debt instrument (as a percent)				5.50%
Notes Issued				400,000,000
Estimated fair value of Notes				401,000,000				401,000,000
Unamortized debt premium				993,000
Long-term Debt				400,993,000
Senior Notes [Member] | Kodiak [Member] | Subsequent Event [Member]
Debt disclosures [Line Items]
Notes Issued			$1,550,000,000
Percentage of redemption price			101.00%

ASSET_RETIREMENT_OBLIGATIONS_D

ASSET RETIREMENT OBLIGATIONS (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013
Asset Retirement Obligations
Asset retirement obligations, current portion	$12,000		$10,000
Reconciliation of the Company's asset retirement obligations
Balance at the beginning of the period	126,148		97,818
Additional liability incurred	29,186		17,535
Revisions in estimated cash flows	25,909	[1]	12,225	[1]
Accretion expense	13,548		10,608
Obligations on sold properties	-7,237		-3,630
Liabilities settled	-7,623		-8,408
Balance at the end of the period	$179,931		$126,148
[1]	Revisions in estimated cash flows during the year ended December 31, 2014 are primarily attributable to increased estimates of future costs for oilfield goods and services required to plug and abandon wells in certain fields in the Rocky Mountains and Permian Basin regions. Revisions in estimated cash flows during the year ended December 31, 2013 were primarily attributable to increased estimates of futures costs for oilfield goods and services required to plug and abandon wells in certain fields in the Rocky Mountains region.

DERIVATIVE_FINANCIAL_INSTRUMEN2

DERIVATIVE FINANCIAL INSTRUMENTS (Derivative instruments) (Details) (Whiting Petroleum Corporation [Member], Crude oil [Member], Subsequent Event [Member])	Feb. 13, 2015
	item
Derivative Financial Instruments [Line Items]
Aggregate notional amount of price risk derivatives (in Bbl)	21,066,060
Three-way collars [Member] | Jan - Dec 2015 [Member]
Derivative Financial Instruments [Line Items]
Aggregate notional amount of price risk derivatives (in Bbl)	3,600,000	[1]
Derivative, Floor Price (in dollars per Bbl)	50.83	[1]
Derivative, Strike Price (in dollars per Bbl)	62.5	[1]
Derivative, Cap Price (in dollars per Bbl)	83.81	[1]
Three-way collars [Member] | Jan - Dec 2016 [Member]
Derivative Financial Instruments [Line Items]
Aggregate notional amount of price risk derivatives (in Bbl)	6,600,000
Derivative, Floor Price (in dollars per Bbl)	43.18
Derivative, Strike Price (in dollars per Bbl)	53.18
Derivative, Cap Price (in dollars per Bbl)	76.26
Collars [Member] | Jan - Dec 2015 [Member]
Derivative Financial Instruments [Line Items]
Aggregate notional amount of price risk derivatives (in Bbl)	1,309,500
Derivative, Floor Price (in dollars per Bbl)	52.47
Derivative, Cap Price (in dollars per Bbl)	59.26
Collars [Member] | Jan - Dec 2016 [Member]
Derivative Financial Instruments [Line Items]
Aggregate notional amount of price risk derivatives (in Bbl)	3,000,000
Derivative, Floor Price (in dollars per Bbl)	51
Derivative, Cap Price (in dollars per Bbl)	63.48
Collars [Member] | Jan - Dec 2017 [Member]
Derivative Financial Instruments [Line Items]
Aggregate notional amount of price risk derivatives (in Bbl)	3,000,000
Derivative, Floor Price (in dollars per Bbl)	53
Derivative, Cap Price (in dollars per Bbl)	70.44
Swap [Member] | Jan - Dec 2015 [Member]
Derivative Financial Instruments [Line Items]
Aggregate notional amount of price risk derivatives (in Bbl)	3,556,560
Derivative, Swap Price (in dollars per Bbl)	86.05
[1]	A three-way collar is a combination of options: a sold call, a purchased put and a sold put. The sold call establishes a maximum price (ceiling) Whiting will receive for the volumes under contract. The purchased put establishes a minimum price (floor), unless the market price falls below the sold put (sub-floor), at which point the minimum price would be NYMEX plus the difference between the purchased put and the sold put strike price.

DERIVATIVE_FINANCIAL_INSTRUMEN3

DERIVATIVE FINANCIAL INSTRUMENTS (Fixed-differential crude oil contracts) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Derivative Financial Instruments [Line Items]
Fair value asset	$53,530,000	$36,416,000	$23,715,000
CO 2 Contract [Member]
Derivative Financial Instruments [Line Items]
The estimated fair value of the embedded derivative in this purchase contract asset	$0

DERIVATIVE_FINANCIAL_INSTRUMEN4

DERIVATIVE FINANCIAL INSTRUMENTS (Schedule of effects of commodity derivative instruments) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013		Dec. 31, 2012
Derivative Financial Instruments [Line Items]
(Gain) Loss Recognized in Income	($100,579)	$7,802		($85,911)
Not Designated as ASC 815 Hedges [Member]
Derivative Financial Instruments [Line Items]
(Gain) Loss Recognized in Income	-100,579	7,802
Commodity contracts [Member] | Not Designated as ASC 815 Hedges [Member]
Derivative Financial Instruments [Line Items]
(Gain) Loss Recognized in Income	-136,995	20,503
Commodity contracts [Member] | ASC 815 Cash Flow Hedging Relationships [Member]
Derivative Financial Instruments [Line Items]
Loss Reclassified from AOCI into Income (Effective Portion)		-1,958	[1]
Embedded commodity contracts [Member] | Not Designated as ASC 815 Hedges [Member]
Derivative Financial Instruments [Line Items]
(Gain) Loss Recognized in Income	$36,416	($12,701)
[1]	Effective April 1, 2009, the Company de-designated all of its commodity derivative contracts that had been previously designated as cash flow hedges and elected to discontinue hedge accounting prospectively. As a result, such mark-to-market values at March 31, 2009 were frozen in AOCI as of the de-designation date and were reclassified into earnings as the original hedged transactions affected income. As of December 31, 2013, all amounts previously in AOCI had been reclassified into earnings.

DERIVATIVE_FINANCIAL_INSTRUMEN5

DERIVATIVE FINANCIAL INSTRUMENTS (Location and fair value of derivative instruments, assets) (Details) (Not Designated as ASC 815 Hedges [Member], USD $)	Dec. 31, 2014		Dec. 31, 2013
In Thousands, unless otherwise specified
Gross amounts of derivative assets and gross amounts offset [Line Items]
Gross Amounts of Recognized Assets	$199,788	[1]	$60,168	[1]
Gross Amounts Offset	-18,752	[1]	-22,478	[1]
Total financial assets	181,036	[1]	37,690	[1]
Commodity contracts [Member] | Derivative Assets [Member]
Gross amounts of derivative assets and gross amounts offset [Line Items]
Gross Amounts of Recognized Assets			23,752	[1]
Gross Amounts Offset			-22,478	[1]
Total financial assets			1,274	[1]
Commodity contracts [Member] | Prepaid Expenses and Other [Member]
Gross amounts of derivative assets and gross amounts offset [Line Items]
Gross Amounts of Recognized Assets	154,329	[1]
Gross Amounts Offset	-18,752	[1]
Total financial assets	135,577	[1]
Commodity contracts [Member] | Other Long Term Assets [Member]
Gross amounts of derivative assets and gross amounts offset [Line Items]
Gross Amounts of Recognized Assets	45,459	[1]
Total financial assets	45,459	[1]
Embedded commodity contracts [Member] | Other Long Term Assets [Member]
Gross amounts of derivative assets and gross amounts offset [Line Items]
Gross Amounts of Recognized Assets			36,416	[1]
Total financial assets			$36,416	[1]
[1]	Because counterparties to the Companybs financial derivative contracts are lenders under Whiting Oil and Gasb credit agreement, which eliminates its need to post or receive collateral associated with its derivative positions, columns for cash collateral pledged or received have not been presented in the tables above.

DERIVATIVE_FINANCIAL_INSTRUMEN6

DERIVATIVE FINANCIAL INSTRUMENTS (Location and fair value of derivative instruments, liabilities) (Details) (Not Designated as ASC 815 Hedges [Member], USD $)	Dec. 31, 2014		Dec. 31, 2013
In Thousands, unless otherwise specified
Gross amounts of derivative liabilities and gross amounts offset [Line Items]
Gross Amounts of Recognized Liabilities	$18,752	[1]	$25,960	[1]
Gross Amounts Offset	-18,752	[1]	-22,478	[1]
Total financial liabilities			3,482	[1]
Commodity contracts [Member]
Gross amounts of derivative liabilities and gross amounts offset [Line Items]
Gross Amounts of Recognized Liabilities	18,752	[1]
Gross Amounts Offset	-18,752	[1]
Commodity contracts [Member] | Accrued Liabilities And Other [Member]
Gross amounts of derivative liabilities and gross amounts offset [Line Items]
Gross Amounts of Recognized Liabilities			25,960	[1]
Gross Amounts Offset			-22,478	[1]
Total financial liabilities			$3,482	[1]
[1]	Because counterparties to the Companybs financial derivative contracts are lenders under Whiting Oil and Gasb credit agreement, which eliminates its need to post or receive collateral associated with its derivative positions, columns for cash collateral pledged or received have not been presented in the tables above.

FAIR_VALUE_MEASUREMENTS_Fair_v

FAIR VALUE MEASUREMENTS (Fair value assets and liabilities measured on a recurring basis) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Financial Assets
Financial assets - current	$135,577	$1,274
Recurring Basis [Member]
Financial Assets
Total financial assets	181,036	37,690
Financial Liabilities
Total financial liabilities		3,482
Recurring Basis [Member] | Commodity contracts [Member]
Financial Assets
Financial assets - current	135,577	1,274
Financial assets - non-current	45,459
Financial Liabilities
Financial liabilities - current		3,482
Recurring Basis [Member] | Embedded commodity contracts [Member]
Financial Assets
Financial assets - non-current		36,416
Recurring Basis [Member] | Level 2 [Member]
Financial Assets
Total financial assets	127,506	1,274
Financial Liabilities
Total financial liabilities		3,482
Recurring Basis [Member] | Level 2 [Member] | Commodity contracts [Member]
Financial Assets
Financial assets - current	127,506	1,274
Financial Liabilities
Financial liabilities - current		3,482
Recurring Basis [Member] | Level 3 [Member]
Financial Assets
Total financial assets	53,530	36,416
Recurring Basis [Member] | Level 3 [Member] | Commodity contracts [Member]
Financial Assets
Financial assets - current	8,071
Financial assets - non-current	45,459
Recurring Basis [Member] | Level 3 [Member] | Embedded commodity contracts [Member]
Financial Assets
Financial assets - non-current		$36,416

FAIR_VALUE_MEASUREMENTS_Reconc

FAIR VALUE MEASUREMENTS (Reconciliation of changes in the fair value of financial assets (liabilities) designated as Level 3 in the valuation hierarchy)(Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013
Reconciliation of changes in the fair value of financial assets (liabilities) designated as Level 3 in the valuation hierarchy
Fair value asset, beginning of period	$36,416		$23,715
Unrealized gains (losses) on commodity derivative contracts included in earnings	17,114	[1]	12,701	[1]
Fair value asset, end of period	$53,530		$36,416
[1]	Included in commodity derivative (gain) loss, net in the consolidated statements of income.

FAIR_VALUE_MEASUREMENTS_Signif

FAIR VALUE MEASUREMENTS (Significant unobservable inputs used in the fair value measurement) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
FAIR VALUE MEASUREMENTS [Line Items]
Fair value asset	$53,530	$36,416	$23,715
Commodity contracts [Member] | Level 3 [Member]
FAIR VALUE MEASUREMENTS [Line Items]
Fair value asset	$53,530
Market Differentail For Crude Oil, Amount (Per Bbl)	5.74

FAIR_VALUE_MEASUREMENTS_Nonfin

FAIR VALUE MEASUREMENTS (Non-financial assets and liabilities measured at fair value on a nonrecurring basis) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Loss (Before Tax) Year	$767,627,000		$358,455,000		$107,855,000
Proved CO2 Properties [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Property, Plant, and Equipment, Fair Value Disclosure	3,000,000
Impairment of Proved Properties	42,000,000
CO2 Properties, Net Carrying Value	45,000,000
Proved Oil and Natural Gas Properties [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Property, Plant, and Equipment, Fair Value Disclosure	176,000,000
Impairment of Proved Properties	587,000,000
Nonrecurring [Member] | Proved Properties [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Property, Plant, and Equipment, Fair Value Disclosure	179,155,000	[1]
Impairment of Proved Properties	629,450,000	[1]
Nonrecurring [Member] | Proved Properties [Member] | Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Property, Plant, and Equipment, Fair Value Disclosure	179,155,000	[1]
Nonrecurring [Member] | Proved Oil and Natural Gas Properties [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Property, Plant, and Equipment, Fair Value Disclosure			106,114,000	[2]
Loss (Before Tax) Year			267,109,000	[2]
Proved Oil and Gas Properties, Net Carrying Value	763,000,000		373,000,000
Nonrecurring [Member] | Proved Oil and Natural Gas Properties [Member] | Rocky Mountains Region And Michigan [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Loss (Before Tax) Year			221,000,000
Nonrecurring [Member] | Proved Oil and Natural Gas Properties [Member] | Rocky Mountains Region [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Loss (Before Tax) Year			46,000,000
Nonrecurring [Member] | Proved Oil and Natural Gas Properties [Member] | Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Property, Plant, and Equipment, Fair Value Disclosure			$106,114,000	[2]
[1]	During the year ended December 31, 2014, proved oil and gas properties with a carrying amount of $763 million were written down to their fair value of $176 million, resulting in a non-cash impairment charge of $587 million. The impairment primarily consisted of non-core oil and gas properties, that are not currently being developed, in Colorado, Louisiana, North Dakota and Utah and related to the decrease in the forward price curve for crude oil and natural gas on December 31, 2014 and the associated decline in oil and gas reserves in those areas. Also during the year ended December 31, 2014, proved CO2 properties at the Bravo Dome field in New Mexico with a carrying amount of $45 million were written down to their fair value of $3 million, resulting in a non-cash impairment charge of $42 million.
[2]	During the year ended December 31, 2013, proved oil and gas properties with a carrying amount of $373 million were written down to their fair value of $106 million, resulting in a non-cash impairment charge of $267 million. The impairment consisted of (i) a $221 million write-down in the Rocky Mountains region and Michigan related to the decrease in the forward price curve for natural gas at December 31, 2013 and the associated decline in gas reserves in those areas and (ii) a $46 million write-down in the Rocky Mountains region related to well performance and associated changes in reserves during the fourth quarter of 2013.

DEFERRED_COMPENSATION_Producti

DEFERRED COMPENSATION (Production participation plan) (Details) (USD $)	12 Months Ended			240 Months Ended	12 Months Ended
	Dec. 31, 2014	Dec. 31, 1995	Dec. 31, 1994	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Jan. 31, 2015
Additional Deferred Compensation
Percentage of employees vesting ratably per year	20.00%
Plan period (years)	5 years
Distribution period after date of termination (months)	12 months
Amount reflected as a current liability	$113,391,000			113,391,000	$73,264,000
Subsequent Event [Member]
Deferred Compensation [Line Items]
Distribution under the Plan							41,000,000
Minimum [Member]
Deferred Compensation [Line Items]
Percentage of overriding royalty interest allocated			2.00%
Percentage of oil and gas sales less lease operating expenses and production taxes allocated	1.75%	1.75%		1.75%
Maximum [Member]
Deferred Compensation [Line Items]
Percentage of overriding royalty interest allocated			3.00%
Percentage of oil and gas sales less lease operating expenses and production taxes allocated	5.00%	5.00%		5.00%
General and administrative expense [Member]
Deferred Compensation [Line Items]
Accrued compensation expense allocation	24,000,000				66,000,000	45,000,000
Exploration expense [Member]
Deferred Compensation [Line Items]
Accrued compensation expense allocation	2,000,000				7,000,000	4,000,000
Postle Properties [Member]
Additional Deferred Compensation
Amount reflected as a current liability					$24,000,000

DEFERRED_COMPENSATION_401K_Pla

DEFERRED COMPENSATION (401K Plan) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
DEFERRED COMPENSATION [Abstract]
Employer's contribution in employees retirement plan	$9	$8	$6
Employees vest in employer contribution Percentage, per year of completed service	20.00%

DEFERRED_COMPENSATION_Schedule

DEFERRED COMPENSATION (Schedule of changes in the plan's estimated long-term liability) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
DEFERRED COMPENSATION [Abstract]
Long-term Production Participation Plan liability at beginning of the period	$87,503	$94,483
Change in liability for accretion, vesting, changes in estimates and new Plan year activity prior to Plan termination		66,284
Change in liability for vesting and PUDs assigned upon Plan termination	25,888
Amount reflected as a current liability	-113,391	-73,264
Long-term Production Participation Plan liability at end of the period		$87,503

SHAREHOLDERS_EQUITY_AND_NONCON2

SHAREHOLDERS' EQUITY AND NONCONTROLLING INTEREST (6.25% Convertible perpetual preferred stock) (Details) (USD $)	1 Months Ended	0 Months Ended	12 Months Ended
	Jun. 30, 2009	Mar. 31, 2013	Dec. 31, 2013	Dec. 31, 2014
Convertible perpetual preferred stock [Member]
Class of Stock [Line Items]
Interest rate on convertible perpetual preferred stock (as a percent)	6.25%
6.25% convertible perpetual preferred stock, shares issued	3,450,000			0
6.25% convertible perpetual preferred stock, shares issue Price per share (in dollars per share)	$100
6.25% convertible perpetual preferred stock, shares outstanding		172,129		0
Dividend on preferred stock per share Per annum (in dollars per share)	$6.25
Common Stock [Member]
Class of Stock [Line Items]
Common stock issued on conversion of preferred stock (in shares)		792,919	794,000

SHAREHOLDERS_EQUITY_AND_NONCON3

SHAREHOLDERS' EQUITY AND NONCONTROLLING INTEREST (Equity incentive plan) (Details) (USD $)	12 Months Ended				0 Months Ended	1 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013	Dec. 31, 2012	Dec. 08, 2014	Jan. 31, 2014	Jan. 31, 2013	Jan. 31, 2012
Share-based compensation disclosures [Line Items]
Stock compensation expense	$23		$22	$18
Stock Option [Member]
Share-based compensation disclosures [Line Items]
Maximum number of Shares per employee	600,000
Vesting (service) period	3 years
Awards Assumed in Kodiak Acquisition (in shares)	673,235
Weighted average period over which cost will be recognized	1 year 2 months 12 days
Granted (in shares)				45,359
Granted date fair value (in dollars per share)				$28.88
Unrecognized compensation cost	1
Stock Appreciation Rights (SARs) [Member]
Share-based compensation disclosures [Line Items]
Maximum number of Shares per employee	600,000
Restricted Stock [Member]
Share-based compensation disclosures [Line Items]
Maximum number of Shares per employee	300,000
Awards Assumed in Kodiak Acquisition (in shares)	304,926	[1]			47,325
Granted (in shares)	907,856		940,792	592,400
Granted (in dollars per share)	$32.41		$27.59	$34.45
Unrecognized compensation cost	13
Weighted average period over which cost will be recognized	1 year 8 months 12 days
Total fair value of restricted stock vested	$31		$17	$19
2013 Equity Plan [Member]
Share-based compensation disclosures [Line Items]
Number of shares authorized upon shareholder's approval	5,300,000
Increase in authorized shares					978,161
Number of options available for grant	5,048,433
Executive officers and employees [Member] | Restricted Stock [Member]
Share-based compensation disclosures [Line Items]
Vesting (service) period	3 years
Minimum [Member] | Stock Option [Member]
Share-based compensation disclosures [Line Items]
Vesting (service) period	1 year
Minimum [Member] | Directors [Member] | Restricted Stock [Member]
Share-based compensation disclosures [Line Items]
Vesting (service) period	1 year
Maximum [Member] | Stock Option [Member]
Share-based compensation disclosures [Line Items]
Vesting (service) period	3 years
Market-based vesting criteria [Member] | Executive officers [Member] | Restricted Stock [Member]
Share-based compensation disclosures [Line Items]
Vesting (service) period	3 years
Granted (in shares)						750,681	751,872	444,501
Granted (in dollars per share)						$26.59	$23.01	$29.45
[1]	Kodiakbs existing restricted stock units and restricted stock awards held by employees, which automatically converted into 257,601 restricted stock units and 47,325 restricted stock awards of Whiting and vested upon closing of the Kodiak Acquisition.

SHAREHOLDERS_EQUITY_AND_NONCON4

SHAREHOLDERS' EQUITY AND NONCONTROLLING INTEREST (Equity awards assumed in Kodiak acquisition) (Details) (USD $)	0 Months Ended		12 Months Ended
	Dec. 08, 2014		Dec. 31, 2014	Dec. 31, 2012
Kodiak [Member]
Business Acquisition [Line Items]
Shares exchanged per each share owned	0.177
Restricted Stock Units (RSUs) [Member]
Business Acquisition [Line Items]
Fair value of Whitingbs common stock issued			$9,596,000
Stock Option [Member]
Business Acquisition [Line Items]
Awards Assumed in Kodiak Acquisition (in shares)			673,235
Fair value of Whitingbs common stock issued			7,523,000
Amount attributed to prior service rendered			7,000,000
Remaining amount to be expensed over remaining service term			1,000,000
Vesting (service) period (in years)			3 years
Weighted average fair value, per share				$28.88
Stock Option [Member] | Maximum [Member]
Business Acquisition [Line Items]
Vesting (service) period (in years)			3 years
Stock Option [Member] | Minimum [Member]
Business Acquisition [Line Items]
Vesting (service) period (in years)			1 year
Stock Option [Member] | Kodiak [Member]
Business Acquisition [Line Items]
Weighted average fair value, per share	12.2
Common Stock [Member] | Restricted Stock Units (RSUs) [Member]
Business Acquisition [Line Items]
Awards Assumed in Kodiak Acquisition (in shares)	257,601		258,000
Common Stock [Member] | Restricted Stock Units (RSUs) [Member] | Kodiak [Member]
Business Acquisition [Line Items]
Fair value of Whitingbs common stock issued	9,596,000	[1]
Common Stock [Member] | Stock Option [Member] | Kodiak [Member]
Business Acquisition [Line Items]
Fair value of Whitingbs common stock issued	7,523,000
[1]	257,601 shares of Whiting common stock issued at $37.25 per share (closing price as of December 5, 2014), based on Kodiakbs 1,455,409 restricted stock units held by employees as of December 8, 2014.

SHAREHOLDERS_EQUITY_AND_NONCON5

SHAREHOLDERS' EQUITY AND NONCONTROLLING INTEREST (Assumption for valuing market based restricted shares) (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
	item	item	item
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Dividend yield (as a percent)	0.00%
Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected volatility (as a percent)			61.40%
Risk-free interest rate (as a percent)			1.19%
Expected term			6 years
Dividend yield (as a percent)			0.00%
Stock Option [Member] | Kodiak [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected volatility (as a percent)	49.70%
Risk-free interest rate (as a percent)	1.90%
Expected term	6 years 1 month 6 days
Stock Option [Member] | Kodiak [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected volatility (as a percent)	40.30%
Risk-free interest rate (as a percent)	0.08%
Expected term	2 years
Market-based vesting criteria [Member] | Executive officers [Member] | Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of simulations	65,000	65,000	65,000
Expected volatility (as a percent)	42.30%	43.10%	51.90%
Risk-free interest rate (as a percent)	0.86%	0.41%	0.35%
Dividend yield (as a percent)	0.00%	0.00%	0.00%

SHAREHOLDERS_EQUITY_AND_NONCON6

SHAREHOLDERS' EQUITY AND NONCONTROLLING INTEREST (Summary of nonvested restricted stock) (Details) (Restricted Stock [Member], USD $)	0 Months Ended	12 Months Ended
	Dec. 08, 2014	Dec. 31, 2014		Dec. 31, 2013	Dec. 31, 2012
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Balance at the beginning of the period (in shares)		1,444,310		951,026	724,395
Granted (in shares)		907,856		940,792	592,400
Awards Assumed in Kodiak Acquisition (in shares)	47,325	304,926	[1]
Vested (in shares)		-814,439		-347,824	-357,170
Forfeited (in shares)		-385,785		-99,684	-8,599
Balance at the end of the period (in shares)		1,456,868		1,444,310	951,026
Balance at the beginning of the period (in dollars per share)		$31.71		$37.02	$29.88
Granted (in dollars per share)		$32.41		$27.59	$34.45
Awards Assumed in Kodiak Acquisition (in dollars per share)		$37.25	[1]
Vested (in dollars per share)		$34.05		$35.32	$17.91
Forfeited (in dollars per share)		$34.86		$30.95	$51.72
Balance at the end of the period (in dollars per share)		$31.16		$31.71	$37.02
[1]	Kodiakbs existing restricted stock units and restricted stock awards held by employees, which automatically converted into 257,601 restricted stock units and 47,325 restricted stock awards of Whiting and vested upon closing of the Kodiak Acquisition.

SHAREHOLDERS_EQUITY_AND_NONCON7

SHAREHOLDERS' EQUITY AND NONCONTROLLING INTEREST (Summary of stock options outstanding) (Details) (Stock Option [Member], USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Balance at the beginning of the period (in shares)	420,840	422,695	377,336
Granted (in shares)			45,359
Options Assumed in Kodiak Acquisition (in shares)	673,235
Exercised (in shares)	-117,123
Forfeited or expired (in shares)	-8,559	-1,855
Balance at the end of the period (in shares)	968,393	420,840	422,695
Options vested and expected to vest (in shares)	905,107
Options exercisable (in shares)	831,220
Balance at the beginning of the period (in dollars per share)	$28.65	$28.79	$26.09
Granted (in dollars per share)			$51.22
Options Assumed in Kodiak Acquisition (in dollars per share)	$44.48
Exercised (in dollars per share)	$15.21
Forfeitures or expired (in dollars per share)	$50.51	$60.28
Balance at the end of the period (in dollars per share)	$41.09	$28.65	$28.79
Options vested and expected to vest (in dollars per share)	$40.78
Options exercisable (in dollars per share)	$38.45
Aggregate Intrinsic Value, options Exercised	$6,203,361
Aggregate Intrinsic Value, options outstanding, end of period	5,216,952
Options vested and expected to vest, Aggregate Intrinsic Value	4,984,431
Options exercisable, Aggregate Intrinsic Value	$5,216,952
Weighted Average Remaining Contractual Term, options outstanding	4 years 9 months 18 days
Weighted Average Remaining Contractual Term, options vested and expected to vest	4 years 9 months 18 days
Weighted Average Remaining Contractual Term, options exercisable	4 years 2 months 12 days

SHAREHOLDERS_EQUITY_AND_NONCON8

SHAREHOLDERS' EQUITY AND NONCONTROLLING INTEREST (Rights Agreement) (Details) (USD $)	0 Months Ended	12 Months Ended
	Feb. 22, 2011	Dec. 31, 2014	Dec. 31, 2006
Rights [Member]
Class of Warrant or Right [Line Items]
Price of one hundredth of a share, Series A Junior Participating Preferred Stock		180
Redemption price per share, Series A Junior Participating Preferred Stock		0.001
Common Stock [Member]
Class of Warrant or Right [Line Items]
Number of preferred share purchase rights declared as a dividend on a common stock			1
Stock split approved	2
Number of rights outstanding per common share		0.5
Minimum percentage ownership for preferred rights price to apply		15.00%
Series A Junior Participating Preferred Stock [Member]
Class of Warrant or Right [Line Items]
Junior Participating Preferred Stock par value		0.001
Series A Junior Participating Preferred Stock [Member] | Rights [Member]
Class of Warrant or Right [Line Items]
Number of securities into which each warrant or right may be converted		0.01

SHAREHOLDERS_EQUITY_AND_NONCON9

SHAREHOLDERS' EQUITY AND NONCONTROLLING INTEREST (Schedule of noncontrolling interest) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Noncontrolling Interest disclosures [Line Items]
Balance at the beginning of the period	$8,132	$8,184
Net income (loss)	-62	-52	-90
Balance at the end of the period	$8,070	$8,132	$8,184
Sustainable Water Resources, LLC [Member]
Noncontrolling Interest disclosures [Line Items]
Third party ownership interest (as a percent)	25.00%

INCOME_TAXES_Narrative_Details

INCOME TAXES (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Operating Loss Carryforwards [Line Items]
EOR credit carryforwards	$7,946,000	$7,946,000
Alternative minimum tax credit carryforwards	15,694,000	18,452,000
Valuation allowance	5,638,000	1,230,000
Income Tax Expense (Benefit)	79,170,000	205,868,000	247,912,000
Unrecognized tax benefits, penalties and interest expense	0
Kodiak [Member]
Operating Loss Carryforwards [Line Items]
Federal operating loss carryforwards	170,000,000
Operating loss carryforwards, maximum utilization per year	77,000,000
Operating loss carryforwards, expiration period	3 years
Whiting Resources Corporation [Member]
Operating Loss Carryforwards [Line Items]
Income Tax Expense (Benefit)	0
Federal [Member]
Operating Loss Carryforwards [Line Items]
Federal operating loss carryforwards	1,700,000,000
Net operating loss carryforwards related to tax deductions that deviate from compensation expense	$70,000,000

INCOME_TAXES_Schedule_of_incom

INCOME TAXES (Schedule of income expense) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
INCOME TAXES [Abstract]
Federal	($2,758)	$7,060
State	5,383	-6,074	-669
Total current income tax expense (refund)	2,625	986	-669
Federal	65,522	196,787	233,468
State	11,023	8,095	15,113
Total deferred income tax expense	76,545	204,882	248,581
Total income tax expense	$79,170	$205,868	$247,912

INCOME_TAXES_Reconciliation_of

INCOME TAXES (Reconciliation of statutory income tax expense to income expense) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
INCOME TAXES [Abstract]
U.S. statutory income tax rate (as a percent)	35.00%	35.00%	35.00%
U.S. statutory income tax expense	$50,371	$200,155	$231,704
State income taxes, net of federal benefit	12,705	13,962	14,444
State income tax credits		-10,525
Statutory depletion	-618	-796	-620
Enacted changes in state tax laws	3,700	-1,416
Market-based equity awards	2,805
Permanent items	3,504	2,122	1,524
Transaction costs	6,936
Other	-233	2,366	860
Total income tax expense	$79,170	$205,868	$247,912

INCOME_TAXES_Components_of_def

INCOME TAXES (Components of deferred income tax assets and liabilities) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
INCOME TAXES [Abstract]
Net operating loss carryforward	$588,330	$438,922
Production Participation Plan Liability	26,942	32,245
Tax sharing liability		9,439
Asset retirement obligations	13,791	23,642
Underwriter fees	14,065	10,974
Restricted stock compensation	15,527	13,384
Premium on Senior Notes	7,979
EOR credit carryforwards	7,946	7,946
Alternative minimum tax credit carryforwards	15,694	18,452
Transaction costs	7,957
Other	9,493	3,234
Total deferred income tax assets	707,724	558,238
Less valuation allowances	-5,638	-1,230
Net deferred income tax assets	702,086	557,008
Oil and gas properties	1,785,926	1,675,916
Trust distributions	129,437	149,332
Derivative instruments	64,898	10,438
Total deferred income tax liabilities	1,980,261	1,835,686
Total net deferred income tax liabilities	$1,278,175	$1,278,678

INCOME_TAXES_Net_deferred_inco

INCOME TAXES (Net deferred income tax liabilities) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
INCOME TAXES [Abstract]
Current deferred income taxes
Current deferred income taxes	47,545	648
Non-current deferred income taxes	1,230,630	1,278,030
Total net deferred income tax liabilities	$1,278,175	$1,278,678

INCOME_TAXES_Liabilities_for_u

INCOME TAXES (Liabilities for unrecognized tax benefits) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2014	Dec. 31, 2013
INCOME TAXES [Abstract]
Balance at the beginning of the period	$299	$170	$170
Decrease related to tax position taken in a prior period	-129
Balance at the end of the period	$170	$170	$170

EARNINGS_PER_SHARE_Narrative_D

EARNINGS PER SHARE (Narrative) (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Restricted Stock [Member]
Shares excluded from Earnings Per Share calculation [Line Items]
Stock options excluded from earnings per share calculation (in shares)	803,902	173,778	141,807
Stock options [Member]
Shares excluded from Earnings Per Share calculation [Line Items]
Restricted stock excluded from earnings per share calculation (in shares)	791	8,689	7,720

EARNINGS_PER_SHARE_Reconciliat

EARNINGS PER SHARE (Reconciliation between basic and diluted earnings per share)(Details) (USD $)	3 Months Ended								12 Months Ended
Share data in Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013		Dec. 31, 2012
Numerator:
Net income available to shareholders									$64,807,000	$366,055,000		$414,189,000
Preferred stock dividends										-494,000	[1]	-1,077,000	[1]
Net income available to common shareholders, basic									64,807,000	365,561,000		413,112,000
Denominator:
Weighted average shares outstanding, basic									122,138	118,260		117,601
Numerator:
Net income available to common shareholders, basic									64,807,000	365,561,000		413,112,000
Preferred stock dividends										538,000		1,077,000
Adjusted net income available to common shareholders, diluted									64,807,000	366,099,000		414,189,000
Denominator:
Weighted average shares outstanding, basic									122,138	118,260		117,601
Restricted stock and stock options (in shares)									381	957		633
Convertible perpetual preferred stock (in shares)										371		794
Weighted average shares outstanding, diluted									122,519	119,588		119,028
Earnings per common share, basic (in dollars per share)	($2.69)	$1.33	$1.27	$0.92	($0.50)	$1.72	$1.14	$0.73	$0.53	$3.09		$3.51
Earnings per common share, diluted (in dollars per share)	($2.68)	$1.32	$1.26	$0.91	($0.50)	$1.71	$1.14	$0.72	$0.53	$3.06		$3.48
Decrease in accumulated preferred stock dividends									$0	$40,000		$0
[1]	For the year ended December 31, 2013, amount includes a decrease of $0.04 million in preferred stock dividends for preferred stock dividends accumulated. There were no accumulated dividend adjustments for the years ended December 31, 2014 or 2012.

RELATED_PARTY_TRANSACTIONS_Nar

RELATED PARTY TRANSACTIONS (Narrative) (Details) (USD $)	12 Months Ended	0 Months Ended	1 Months Ended	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Jan. 28, 2015	Mar. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
		MBoe
Whiting USA Trust I [Member]
Related Party Transaction [Line Items]
Percentage of ownership in subsidiary	15.80%
Whiting's ownership interest (in units)	2,186,389
Payments of unit distributions, net of state tax withholdings	$30
Distributions back from the trust	5
Whiting USA Trust I [Member] | Subsequent Event [Member]
Related Party Transaction [Line Items]
Termination of net profits interest, cumulative production from underlying properties (in MBOE)		9,110
Proved producing reserves conveyed (in MBOE)		8,200
Alliant Energy Corporation [Member]
Related Party Transaction [Line Items]
Percentage of tax benefits due to affiliate related to step-up of tax basis assets	90.00%
Payments under agreement			26	2	2
Interest expense			$3	$3	$2
Working interest in offshore platforms (as a percent)	6.00%
Number of offshore platforms in California that the Company has working interest in	3

RELATED_PARTY_TRANSACTIONS_Sum

RELATED PARTY TRANSACTIONS (Summary of related party receivable and payable balances) (Details) (Whiting USA Trust I [Member], USD $)	Dec. 31, 2014		Dec. 31, 2013
In Thousands, unless otherwise specified
Whiting USA Trust I [Member]
Related Party Transaction [Line Items]
Unit distributions due from Trust I	$652	[1]	$1,093	[1]
Unit distributions payable to Trust I	$4,133	[2]	$6,932	[2]
Percentage of ownership in subsidiary	15.80%
[1]	This amount represents Whitingbs 15.8% interest in the net proceeds due from Trust I and is included within accounts receivable trade, net in the Companybs consolidated balance sheets.
[2]	This amount represents net proceeds from Trust Ibs underlying properties that the Company has received between the last Trust I distribution date and December 31, 2014 and 2013, respectively, but which the Company has not yet distributed to Trust I as of December 31, 2014 and 2013, respectively. Due to ongoing processing of Trust I revenues and expenses after December 31, 2014 and 2013, the amount of Whitingbs next scheduled distribution to Trust I, and the related distribution by Trust I to its unitholders, will differ from this amount. These amounts are included within accounts payable trade in the Companybs consolidated balance sheet.

COMMITMENTS_AND_CONTINGENCIES_1

COMMITMENTS AND CONTINGENCIES (Narrative) (Details) (USD $)	12 Months Ended			2 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Feb. 27, 2015
				contract
Unrecorded Unconditional Purchase Obligation [Line Items]
Rental expense	$7	$5	$6
Subsequent Event [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Number of contracts with drilling rig companies terminated early				5
Termination penalties				27
Dickinson, North Dakota office [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Administrative office space (in square feet)	20,000
Midland, Texas office [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Administrative office space (in square feet)	47,900
Expiration 2016 [Member] | Denver, Colorado office [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Administrative office space (in square feet)	36,300
Expiration 2016 And 2017 [Member] | Subsequent Event [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Number of contracts with drilling rig companies				13
Expiration 2019 [Member] | Denver, Colorado office [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Administrative office space (in square feet)	197,000
Drilling Rig Contracts [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Number of contracts with drilling rig companies	18
Termination penalties	212
Amount spent under contractual commitment	$106	$93	$101
Drilling Rig Contracts [Member] | Expiration 2016 [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Number of contracts with drilling rig companies	7
Drilling Rig Contracts [Member] | Expiration 2017 [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Number of contracts with drilling rig companies	6

COMMITMENTS_AND_CONTINGENCIES_2

COMMITMENTS AND CONTINGENCIES (Narrative II) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
	contract
Unrecorded Unconditional Purchase Obligation [Line Items]
Number of pipeline transportation agreements	3
Ship-Or-Pay Arrangements [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Number of Ship or pay agreements	2
Future commitments under purchase agreements	$20,000,000
Crude oil [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Delivery commitments for year 2015	12,400
Delivery commitments for year 2016	17,800
Delivery commitments for year 2017	19,600
Delivery commitments for year 2018	21,500
Delivery commitments for year 2019	23,300
Delivery commitments for year 2020	6,000
Anticipated under-delivery of contractual volume	10,400
Impact on earnings and financing needs resulting from inability to meet oil and gas delivery commitments	49,000,000
Period in which under-delivery of volume is anticipated	5 years
Take-Or-Pay Agreements [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Number of take or pay purchase agreements	3
Payments under purchase contracts	105,000,000	84,000,000	83,000,000
Future commitments under purchase agreements	149,000,000
Pipeline Transportation Agreements [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Future commitments under purchase agreements	94,438,000
Natural Gas, CO2 And Water Contracts [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Payments under purchase contracts	13,000,000	4,000,000	3,000,000
Future commitments under purchase agreements	$114,000,000
Expiration 2015 [Member] | Ship-Or-Pay Arrangements [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Number of Ship or pay agreements	1
Expiration 2015 [Member] | Take-Or-Pay Agreements [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Number of take or pay purchase agreements	1
Expiration 2017 [Member] | Ship-Or-Pay Arrangements [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Number of Ship or pay agreements	1
Expiration 2017 [Member] | Take-Or-Pay Agreements [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Number of take or pay purchase agreements	2
Expiration 2024 [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Number of pipeline transportation agreements	1
Expiration 2025 [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Number of pipeline transportation agreements	2

COMMITMENTS_AND_CONTINGENCIES_3

COMMITMENTS AND CONTINGENCIES (Minimum future payments under non-cancelable operating leases and unconditional purchase obligations) (Details) (USD $)	Dec. 31, 2014
In Thousands, unless otherwise specified
Unrecorded Unconditional Purchase Obligation [Line Items]
2015	$159,781
2016	119,124
2017	46,957
2018	16,252
2019	15,403
Thereafter	50,307
Total	407,824
Non-Cancelable Leases [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
2015	7,692
2016	7,547
2017	6,610
2018	6,693
2019	5,844
Thereafter	216
Total	34,602
Drilling Rig Contracts [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
2015	146,141
2016	101,855
2017	30,788
Total	278,784
Pipeline Transportation Agreements [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
2015	5,948
2016	9,722
2017	9,559
2018	9,559
2019	9,559
Thereafter	50,091
Total	$94,438

SUBSEQUENT_EVENT_Details

SUBSEQUENT EVENT (Details) (Senior Notes [Member], Subsequent Event [Member], Kodiak [Member], USD $)	0 Months Ended
	Jan. 07, 2015	Jan. 07, 2015
Senior Notes [Member] | Subsequent Event [Member] | Kodiak [Member]
Subsequent Event [Line Items]
Percentage of redemption price	101.00%
Outstanding debt	$1,550,000,000	$1,550,000,000

OIL_AND_GAS_ACTIVITIES_Schedul

OIL AND GAS ACTIVITIES (Schedule of cost Incurred in oil and gas producing activities) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012		Dec. 08, 2014
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Development	$2,891,893,000	[1]	$2,132,824,000	[1]	$1,667,182,000	[1]
Proved property acquisition	2,278,855,000	[2]	232,572,000	[2]	19,785,000	[2]
Unproved property acquisition	1,035,439,000	[2]	174,103,000	[2]	119,175,000	[2]
Exploration	216,587,000		363,234,000		436,084,000
Total	6,422,774,000		2,902,733,000		2,242,226,000
Addition to Oil and Gas Properties for Asset Retirement Costs related to new wells drilled or acquired	45,000,000		30,000,000		36,000,000
Proved properties	12,956,834,000		9,196,845,000
Unproved leasehold costs	1,232,040,000		372,298,000
Kodiak [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Proved properties							2,266,607,000
Unproved leasehold costs							$1,000,396,000
[1]	During 2014, 2013 and 2012, non-cash additions to oil and gas properties of $45 million, $30 million and $36 million, respectively, which relate to estimated costs of the future plugging and abandonment of the Companybs oil and gas wells, are included in development costs in the table above.
[2]	During 2014, amounts include $2.3 billion of non-cash proved property additions and $1.0 billion of non-cash unproved property additions related to the Kodiak Acquisition.

OIL_AND_GAS_ACTIVITIES_Net_cap

OIL AND GAS ACTIVITIES (Net capitalized costs related to the Companybs oil and gas producing activities) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
OIL AND GAS ACTIVITIES [Abstract]
Proved oil and gas properties	$12,956,834	$9,196,845
Unproved oil and gas properties	1,992,868	868,305
Accumulated depletion	-3,003,270	-2,645,841
Oil and gas properties, net	$11,946,432	$7,419,309

OIL_AND_GAS_ACTIVITIES_Net_cha

OIL AND GAS ACTIVITIES (Net changes in capitalized exploratory well costs) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
OIL AND GAS ACTIVITIES [Abstract]
Balance at the beginning of the period	$85,378	$108,861	$90,519
Additions to capitalized exploratory well costs pending the determination of proved reserves	145,336	281,951	384,223
Reclassifications to wells, facilities and equipment based on the determination of proved reserves	-200,869	-291,962	-358,625
Capitalized exploratory well costs charged to expense	-15,552	-13,472	-7,256
Balance at the end of the period	14,293	85,378	108,861
Capitalized exploratory cost for exploratory wells in progress	$0

DISCLOSURES_ABOUT_OIL_AND_GAS_2

DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (Narrative) (Details) (USD $)	12 Months Ended					240 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 1995	Dec. 31, 1994	Dec. 31, 2014
Percentage of proved reserve quantities and related future cash flows reviewed by independent petroleum engineers	100.00%					100.00%
Increase (Decrease) in undiscounted future cash flow if hedging impact considered	($7)	$0	($20)
Maximum [Member]
Percentage of overriding royalty interest allocated					3.00%
Percentage of oil and gas sales less lease operating expenses and production taxes allocated	5.00%			5.00%		5.00%
Minimum [Member]
Percentage of overriding royalty interest allocated					2.00%
Percentage of oil and gas sales less lease operating expenses and production taxes allocated	1.75%			1.75%		1.75%

DISCLOSURES_ABOUT_OIL_AND_GAS_3

DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (Summary of changes in quantities of proved oil and gas reserve) (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	MBoe	MBoe	MBoe	MBoe
Reserve Quantities [Line Items]
Beginning balance of proved oil and gas reserve	438,542	378,760	345,249
Extensions and discoveries	174,811	108,772	81,479
Sales of minerals in place	-2,130	-43,838	-10,611
Purchase of minerals in place	195,609	17,146
Production	-41,804	-34,342	-30,209
Revisions to previous estimates	15,288	12,044	-7,148
Ending balance of proved oil and gas reserves	780,316	438,542	378,760
Proved developed reserves	412,234	252,446	241,864	238,300
Proved undeveloped reserves	368,082	186,096	136,896	106,949
Oil [Member]
Reserve Quantities [Line Items]
Beginning balance of proved oil and gas reserve	347,421	301,285	260,144
Extensions and discoveries	146,122	88,293	68,134
Sales of minerals in place	-1,642	-36,992	-7,960
Purchases of minerals in place	169,586	14,543
Production	-33,485	-27,035	-23,139
Revisions to previous estimates	15,627	7,327	4,106
Ending balance of proved oil and gas reserves	643,629	347,421	301,285
Proved developed reserves	333,593	198,204	190,845	180,975
Proved undeveloped reserves	310,036	149,217	110,440	79,169
NGLs [Member]
Reserve Quantities [Line Items]
Beginning balance of proved oil and gas reserve	44,869	40,098	37,609
Extensions and discoveries	12,947	9,830	6,526
Sales of minerals in place		-4,777	-320
Purchases of minerals in place		1,311
Production	-3,283	-2,821	-2,766
Revisions to previous estimates	151	1,228	-951
Ending balance of proved oil and gas reserves	54,684	44,869	40,098
Proved developed reserves	28,935	23,721	24,204	22,109
Proved undeveloped reserves	25,749	21,148	15,894	15,500
Natural Gas [Member]
Reserve Quantities [Line Items]
Beginning balance of proved oil and gas reserve	277,514	224,264	284,975
Extensions and discoveries	94,452	63,893	40,915
Sales of minerals in place	-2,925	-12,411	-13,987
Purchases of minerals in place	156,140	7,751
Production	-30,218	-26,917	-25,827
Revisions to previous estimates	-2,943	20,934	-61,812
Ending balance of proved oil and gas reserves	492,020	277,514	224,264
Proved developed reserves	298,237	183,129	160,893	211,297
Proved undeveloped reserves	193,783	94,385	63,371	73,678

DISCLOSURES_ABOUT_OIL_AND_GAS_4

DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (Summary of changes in quantities of proved oil and gas reserve-Narrative) (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Sep. 20, 2013	Dec. 08, 2014
	MBoe	item	item	item	item
	item	MBoe	MBoe
Reserve Quantities [Line Items]
Extensions and discoveries	174,811	108,772	81,479
Sales of minerals in place	2,130	43,838	10,611
Purchase of minerals in place	195,609	17,146
Revisions to previous estimates	15,288	12,044	-7,148
Revisions to estimated caused by higher crude oil prices incorporated into the Company's reserve estimates	15,600	4,900	11,800
Revisions to estimated attributable to reservoir analysis and well performance	300	7,100	4,700
Williston Basin [Member]
Reserve Quantities [Line Items]
Number of wells acquired				121
Kodiak [Member]
Reserve Quantities [Line Items]
Number of wells acquired					778

DISCLOSURES_ABOUT_OIL_AND_GAS_5

DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
In Thousands, unless otherwise specified
DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES [Abstract]
Future cash flows	$59,949,707	$35,178,399	$29,308,752
Future production costs	-20,772,234	-12,973,292	-11,397,332
Future development costs	-7,924,573	-5,355,383	-3,181,618
Future income tax expense	-8,579,237	-3,954,401	-4,278,529
Future net cash flows	22,673,663	12,895,323	10,451,273
10% annual discount for estimated timing of cash flows	-11,830,243	-6,301,462	-5,044,240
Standardized measure of discounted future net cash flows	$10,843,420	$6,593,861	$5,407,033	$5,272,492

DISCLOSURES_ABOUT_OIL_AND_GAS_6

DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (Changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES [Abstract]
Beginning of year	$6,593,861	$5,407,033	$5,272,492
Sale of oil and gas produced, net of production costs	-2,274,682	-2,010,925	-1,589,665
Sales of minerals in place	-48,532	-1,064,195	-438,614
Net changes in prices and production costs	81,522	902,916	-1,061,495
Extensions, discoveries and improved recoveries	3,950,413	2,827,321	3,708,780
Previously estimated development costs incurred during the period	1,149,926	832,096	526,982
Changes in estimated future development costs	-3,382,849	-1,264,189	-1,498,592
Purchases of minerals in place	4,420,417	445,669
Revisions of previous quantity estimates	345,775	313,069	-295,432
Net change in income taxes	-651,817	-335,637	255,328
Accretion of discount	659,386	540,703	527,249
End of year	$10,843,420	$6,593,861	$5,407,033

DISCLOSURES_ABOUT_OIL_AND_GAS_7

DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves calculating average sales prices) (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Oil (per Bbl) [Member]
Weighted Average Sales Price [Line Items]
Weighted average sales price	84.69	90.8	87.15
NGLs (per Bbl) [Member]
Weighted Average Sales Price [Line Items]
Weighted average sales price	46.59	54.38	58.15
Natural Gas (per Mcf) [Member]
Weighted Average Sales Price [Line Items]
Weighted average sales price	5.88	4.3	3.21

QUARTERLY_FINANCIAL_DATA_Detai

QUARTERLY FINANCIAL DATA (Details) (USD $)	3 Months Ended																12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014		Sep. 30, 2014		Jun. 30, 2014		Mar. 31, 2014		Dec. 31, 2013		Sep. 30, 2013		Jun. 30, 2013		Mar. 31, 2013		Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
QUARTERLY FINANCIAL DATA [Abstract]
Oil, NGL and natural gas sales	$672,553		$805,054		$825,760		$721,250		$703,024		$706,543		$651,868		$605,114		$3,024,617	$2,666,549	$2,137,714
Operating profit	177,722	[1]	326,215	[1]	370,033	[1]	311,169	[1]	280,311	[1]	316,764	[1]	269,528	[1]	252,806	[1]
Net income	($353,693)		$157,961		$151,426		$109,051		($59,276)		$204,091		$134,944		$86,244		$64,745	$366,003	$414,099
Basic (in dollars per share)	($2.69)		$1.33		$1.27		$0.92		($0.50)		$1.72		$1.14		$0.73		$0.53	$3.09	$3.51
Diluted (in dollars per share)	($2.68)		$1.32		$1.26		$0.91		($0.50)		$1.71		$1.14		$0.72		$0.53	$3.06	$3.48
[1]	Oil, NGL and natural gas sales less lease operating expense, production taxes and depreciation, depletion and amortization.

SCHEDULE_I_CONDENSED_FINANCIAL1

SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT (Condensed balance sheets) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Condensed Financial Statements, Captions [Line Items]
Current assets	$842,999	$1,069,618
TOTAL ASSETS	14,019,504	8,833,470
Current liabilities	1,208,516	777,685
Long-term debt	5,628,782	2,653,834
Other long-term liabilities	20,486	4,212
Shareholders' equity	5,694,974	3,828,567
TOTAL LIABILITIES AND EQUITY	14,019,504	8,833,470
Whiting Petroleum Corporation [Member]
Condensed Financial Statements, Captions [Line Items]
Current assets	3,859	5,120
Investment in subsidiaries	5,464,763	2,707,184
Intercompany receivable	2,907,270	3,796,321
TOTAL ASSETS	8,375,892	6,508,625
Current liabilities	27,738	26,054
Long-term debt	2,653,180	2,653,834
Other long-term liabilities		170
Shareholders' equity	5,694,974	3,828,567
TOTAL LIABILITIES AND EQUITY	$8,375,892	$6,508,625

SCHEDULE_I_CONDENSED_FINANCIAL2

SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT (Condensed statements of operations and comprehensive income) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Condensed Financial Statements, Captions [Line Items]
General and administrative	($177,211)	($137,994)	($108,573)
Interest expense	-170,642	-112,936	-75,210
INCOME BEFORE INCOME TAXES	143,915	571,871	662,011
Income tax benefit	79,170	205,868	247,912
NET INCOME AVAILABLE TO SHAREHOLDERS	64,807	366,055	414,189
COMPREHENSIVE INCOME ATTRIBUTABLE TO WHITING	64,807	367,291	412,713
Whiting Petroleum Corporation [Member]
Condensed Financial Statements, Captions [Line Items]
General and administrative	-1,010	-1,131	-16,506
Interest expense	-1,864	-2,922	-2,168
Equity in earnings of subsidiaries	66,100	361,732	425,870
INCOME BEFORE INCOME TAXES	63,226	357,679	407,196
Income tax benefit	1,581	8,376	6,993
NET INCOME AVAILABLE TO SHAREHOLDERS	64,807	366,055	414,189
COMPREHENSIVE INCOME ATTRIBUTABLE TO WHITING	$64,807	$366,055	$414,189

SCHEDULE_I_CONDENSED_FINANCIAL3

SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT (Condensed statements of cash flows) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Condensed Financial Statements, Captions [Line Items]
Cash flows provided by operating activities	$1,815,302	$1,744,745	$1,401,215
Redemption of 7% Senior Subordinated Notes due 2014		-253,988
Net cash provided by financing activities	423,855	812,414	408,092
Beginning of period	699,460	44,800	15,811
End of period	78,100	699,460	44,800
Fair value of equity issued and debt assumed in the Kodiak Acquisition	4,289,088
Preferred stock dividends paid		-538	-1,077
Whiting Petroleum Corporation [Member]
Condensed Financial Statements, Captions [Line Items]
Cash flows provided by operating activities			16,423
Intercompany receivable	26,373	-2,048,253	-14,094
Redemption of 7% Senior Subordinated Notes due 2014		-253,988
Other financing activities	-26,373	-1,759	-2,329
Net cash provided by financing activities			-16,423
Fair value of equity issued and debt assumed in the Kodiak Acquisition	2,696,094
Distributions from Whiting USA Trust I	4,614	4,749	5,827
Preferred stock dividends paid		-538	-1,077
5% Senior Notes due 2019 [Member] | Senior Notes [Member]
Condensed Financial Statements, Captions [Line Items]
Issuance of Senior Notes		1,100,000
Interest Rate (as a percent)	5.00%	5.00%
5% Senior Notes due 2019 [Member] | Senior Notes [Member] | Whiting Petroleum Corporation [Member]
Condensed Financial Statements, Captions [Line Items]
Issuance of Senior Notes		1,100,000
Interest Rate (as a percent)	5.00%	5.00%	5.00%
5.75% Senior Notes due 2021 [Member] | Senior Notes [Member]
Condensed Financial Statements, Captions [Line Items]
Issuance of Senior Notes		1,204,000
Interest Rate (as a percent)	5.75%	5.75%
5.75% Senior Notes due 2021 [Member] | Senior Notes [Member] | Whiting Petroleum Corporation [Member]
Condensed Financial Statements, Captions [Line Items]
Issuance of Senior Notes		$1,204,000
Interest Rate (as a percent)	5.75%	5.75%
7% Senior Subordinated Notes due 2014 [Member] | Senior Subordinated Notes [Member]
Condensed Financial Statements, Captions [Line Items]
Interest Rate (as a percent)		7.00%
7% Senior Subordinated Notes due 2014 [Member] | Senior Subordinated Notes [Member] | Whiting Petroleum Corporation [Member]
Condensed Financial Statements, Captions [Line Items]
Interest Rate (as a percent)		7.00%

SCHEDULE_I_CONDENSED_FINANCIAL4

SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT (Basis of presentation) (Details) (Whiting Petroleum Corporation [Member], USD $)	Dec. 31, 2014
In Billions, unless otherwise specified
Whiting Petroleum Corporation [Member]
Restricted net assets	$6.90

SCHEDULE_I_CONDENSED_FINANCIAL5

SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT (Long-term debt and other-long term liabilities) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Sep. 30, 2010	Sep. 30, 2013	Sep. 26, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Debt Instrument [Line Items]
Long-term debt	$5,628,782	$2,653,834
Senior Subordinated Notes [Member] | 6.5% Senior Subordinated Notes due 2018 [Member]
Debt Instrument [Line Items]
Interest rate on debt instrument (as a percent)	6.50%	6.50%	6.50%
Senior Notes [Member] | 5% Senior Notes due 2019 [Member]
Debt Instrument [Line Items]
Interest rate on debt instrument (as a percent)	5.00%	5.00%		5.00%
Senior Notes [Member] | 5.75% Senior Notes due 2021 [Member]
Debt Instrument [Line Items]
Interest rate on debt instrument (as a percent)	5.75%	5.75%		5.75%	5.75%
Unamortized debt premium	3,180	3,834
Whiting Petroleum Corporation [Member]
Debt Instrument [Line Items]
Long-term debt	2,653,180	2,653,834
Other		170
Total long-term debt and other long-term liabilities	2,653,180	2,654,004
Whiting Petroleum Corporation [Member] | Senior Subordinated Notes [Member] | 6.5% Senior Subordinated Notes due 2018 [Member]
Debt Instrument [Line Items]
Long-term debt	350,000	350,000
Whiting Petroleum Corporation [Member] | Senior Notes [Member] | 5% Senior Notes due 2019 [Member]
Debt Instrument [Line Items]
Long-term debt	1,100,000	1,100,000
Interest rate on debt instrument (as a percent)	5.00%	5.00%				5.00%
Whiting Petroleum Corporation [Member] | Senior Notes [Member] | 5.75% Senior Notes due 2021 [Member]
Debt Instrument [Line Items]
Long-term debt	$1,203,180	$1,203,834
Interest rate on debt instrument (as a percent)	5.75%	5.75%

SCHEDULE_I_CONDENSED_FINANCIAL6

SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT (Schedule of five succeeding fiscal years of scheduled maturities for long-term debt) (Details) (USD $)	Dec. 31, 2014
In Thousands, unless otherwise specified
2018	$350,000	[1]
2019	3,300,000	[1]
Whiting Petroleum Corporation [Member]
2018	350,000
2019	1,100,000
Thereafter	1,200,000
Total	$2,650,000
[1]	Refer to bKodiak Senior Notes Repurchase Offerb below for more information.

SCHEDULE_I_CONDENSED_FINANCIAL7

SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT (Shareholders' equity) (Details) (USD $)	0 Months Ended	12 Months Ended	1 Months Ended
	Mar. 31, 2013	Dec. 31, 2013	Jun. 30, 2009	Mar. 31, 2013	Dec. 31, 2014
Common Stock [Member]
Class of Stock [Line Items]
Conversion of preferred stock to common (in shares)	792,919	794,000
Convertible perpetual preferred stock [Member]
Class of Stock [Line Items]
Convertible perpetual preferred stock (as a percent)			6.25%
6.25% convertible perpetual preferred stock, shares issued			3,450,000		0
6.25% convertible perpetual preferred stock, shares issue Price per share (in dollars per share)			$100
Preferred stock remained outstanding	172,129			172,129	0
Convertible perpetual preferred stock [Member] | Whiting Petroleum Corporation [Member]
Class of Stock [Line Items]
Convertible perpetual preferred stock (as a percent)			6.25%
6.25% convertible perpetual preferred stock, shares issued			3,450,000
6.25% convertible perpetual preferred stock, shares issue Price per share (in dollars per share)			$100
Preferred stock remained outstanding	172,129			172,129	0
Conversion of preferred stock to common (in shares)				792,919